bluuebunny/crossref_metadata_2025 huggingface dataset:
Apparatus and Method for Strain Energy Based Resiliency Measurement of Loss Control Materials
Authors: Amanullah Md , Alouhali Raed , AlArfaj Mohammed
Published: December 2021

Loss of circulation is one of the greatest challenges that are frequently encountered while drilling. Various types of LCM products are used by the industry to combat loss of circulation. Characterization of these LCM products is very important to select the most suitable products to improve the success rate of LCM treatment jobs. This paper describes the theoretical basis of the application of strain energy along with the development of a strain energy-based mathematical model to create a dedicated software driven novel method and test apparatus for quick and reliable measurement of the coefficient of resiliency of various LCM products to improve the likelihood and probability of success rate of LCM treatment jobs. The simple but reliable method and apparatus provide a fit-for-purpose solution for additional characterization of LCM products.

The design and construction of the test device and the development of the method considered the most critical technical factors that have high impact on data reliability, data accuracy, repeatability and data sensitivity. The components of the test device were selected based on technical, economical, portability and ease of operation using a dedicated software driven method and data acquisition system.

Experimental results generated by loading and unloading a particular mass of a LCM product under a constant displacement rate of the loading foot of the test apparatus demonstrated the suitability of the method and the apparatus in determining the coefficient of resiliency of LCM products. Based on the area below the loading curve i.e. the strain energy absorbed during the loading cycle and the area below the unloading curve i.e. the strain energy desorbed during the unloading cycle, the data acquisition software automatically calculates the coefficient of resiliency of the LCM products.

The resilient characteristic of LCM products is one of the critical factors that is very important for high performance pill or slurry design to enhance the seal/plug stability. Hence, the newly developed method and apparatus will play a positive role to improve the probability and the likelihood of creating a stable and lasting seal/plug in the loss zones. As loss control materials with good resilient properties are highly adaptable in changing stress and pressure conditions, this method can provide appropriate guidelines to mud chemists, mud engineers and mud consultants in designing high performance LCM blends or slurries to combat moderate and severe loss of circulation.
The Importance of Subsurface Characterization and Monitoring During Development and Operation of Underground Gas Storage Facilities
Authors: Guises Romain , Auger Emmanuel , Bordoloi Sanjeev , Ofi Ayodele , Cranfield Colin , Freitag Hans-Christian
Published: December 2021

Natural gas consumption is expected to grow significantly in coming decades in response to cleaner energy initiatives. Underground gas storage (UGS) will be key to addressing supply and demand dynamics for this transition to be successful. This technical paper will demonstrate the importance of an integrated subsurface characterization and monitoring approach not only for the construction of UGS, but also to guarantee safe and efficient operation over many decades.

Key to long-term success of UGS is maximizing working capacity with respect to volume and pressure and maintaining well injection and withdrawal capabilities. Initial assessment steps involve determination of maximum storage capacity and an estimation of required cushion gas volumes. In similar manner to conventional field evaluation, we perform an integrated geological, geophysical, petrophysical and geomechanical characterization of the subsurface. However, for UGS facilities, the impact of cyclic variations of reservoir pressures on subsurface behavior and cap rock integrity also needs to be evaluated to determine safe operating limits at every point in time during the life of the UGS project.

The holistic approach described above allows the operator to optimize the number of wells, well placement, completion design, etc. to ensure long-term safe and efficient operations. Furthermore, close integration of subsurface understanding with optimization of surface facilities, such as the compression system, is another critical component to ensure optimum UGS performance and deliverability. Moreover, another important task of the final phase of UGS facilities design involves enablement of sustainable operation through an asset integrity management plan. This phase is articulated around reservoir surveillance plans that monitor pressure, rock deformation and seismicity, in addition to regular wellbore inspection. Through close operations monitoring and the utilization of advanced data analytics, observations are compared to existing models for validation and operation optimization. Importantly we show that adapted monitoring programs provide critical long-term insight regarding the field response during successive cycles, leading to significant improvement in working gas capacity.

A key consideration of this integrated UGS development strategy is based on the seamless integration of subsurface characterization, wellbore construction and well completions to ensure technical and commercial flexibility. The approach also emphasizes the integration with surface facilities design to ensure a true "Storage to Consumer" view for effective de-bottlenecking. Coupled with integrated subsurface integrity monitoring, this ensures a faster, cost efficient and safe response to the construction and operation of UGS facilities.
A Comprehensive Model Integrating the Stress Sensitivity for Pressure Transient Behavior Study on the Two-Zone System for Offshore Loose Sandstone Reservoirs
Authors: Cao Chong , Cheng Linsong , Zhang Xiangyang , Jia Pin , Lu Wenpei
Published: December 2021

Permeability changes in the weakly consolidated sandstone formation, caused by sand migration, has a serious impact on the interpretation of well testing and production prediction. In this article, a two-zone comprehensive model is presented to describe the changes in permeability by integrating the produced sand, stress sensitivity characteristics. In this model, inner zone is modeled as a higher permeability radial reservoir because of the sand migration, while the outer zone is considered as a lower permeability reservoir. Besides, non-Newtonian fluid flow characteristics are considered as threshold pressure gradient in this paper. As a result, this bi-zone comprehensive model is built. The analytical solution to this composite model can be obtained using Laplace transformation, orthogonal transformation, and then the bottomhole pressure in real space can be solved by Stehfest and perturbation inversion techniques. Based on the oilfield cases validated in the oilfield data from the produced sand horizontal well, the flow regimes analysis shows seven flow regimes can be divided in this bi-zone model considering stress sensitive. In addition, the proposed new model is validated by the compassion results of traditional method without the complex factors. Besides, the effect related parameters of stress sensitivity coefficient, skin factor, permeability ratio and sanding radius on the typical curves of well-testing are analyzed. This work introduces two-zone composite model to reflect the variations of permeability caused by the produced sand in the unconsolidated sandstone formation, which can produce great influence on pressure transient behavior. Besides, this paper can also provide a more accurate reference for reservoir engineers in well test interpretation of loose sandstone reservoirs.
Recovery Improvement Using Geological, Technical and Operational Factors of Field Development That Influence the Character of Inflow Profiles in Horizontal Laterals
Authors: Husein Nadir , Malyavko Evgeny , Novikov Igor , Drobot Albina , Buyanov Anton , Potapova Ekaterina , Upadhye Vishwajit
Published: December 2021

Currently, it is hard to imagine oil field development management without various surveys, involving resource optimisation for more economical reserves recovery. In this context, the application of new technologies aimed at diagnostics of the state of producing wells opens up multiple opportunities to identify the causes of premature water flooding and reduction in oil production, clarify the geology of the developed deposit, and obtain other useful information in a cost-efficient manner.

For several decades now, well logging has been the source of information for field operators on the producing reservoir performance and the composition of fluid flowing across the reservoir through target intervals. However, in the course of time, the industry tends to seek advanced technologies and alternative production logging techniques for well performance diagnostics. Marker-based production logging is just one of the techniques employed to obtain additional data that can be extremely important for prompt decision-making in case of any complicating factors. At the same time, such information requires proper processing and interpretation.

The information on how various factors impact the production profile helps develop a set of measures to adjust the oil flow into the well. In this regard, the task above offers a promising outlook for improving the development system efficiency using selective reservoir stimulation, as far as unconventional reservoirs and hard-to-recover reserves are concerned. Therefore, the upstream industry puts a strong focus on further research in this area today.
Forward Stratigraphic Modeling of Kuwait Formation, Linking Facies Architecture to Hydrocarbon Occurrence
Authors: Amer Aimen , Najem Ali Gadalla , Al-Hajeri Mubarak , Courtade Sergio , Salomonsen Per
Published: December 2021

The objective of this study is to perform forward stratigraphic modeling on the Kuwait Formation (also known as Kuwait Group) exposed stratigraphic succession along the Jal Az-Zor escarpment to explain the enigmatic occurrence of an elongated NW-SE geobody mapped from subsurface data at northern Kuwait.

Outcrop measurements such as; stratigraphic successions, facies distribution, critical facies trends, and paleocurrent analysis have been collected along the 60 km length of the Jal Az-Zor escarpment. Such measurements were combined with thin section lab analysis to reveal the various sedimentary processes such as wave activity, grain size distribution, sediment supply sources, accommodation space, and erosional rates. These measurements were combined with subsurface data such as seismic attributes to reconstruct the paleography of the area and run a forward stratigraphic model simulation. The vertical succession was also utilized to reconstruct the relative sea-level fluctuation through time to develop an accurate model.

Forward stratigraphic modeling resulted in building a robust and reliable facies distribution 3D model for the Jal Az-Zor escarpment that demonstrates the complex facies architecture. The model shows the various stacking patterns of several depositional sequences that are observed in the field as well as the subsurface. The enigmatic geobody mapped from seismic as a channel system in previous publications turned out to be a paleoshoreline. This shoreline is composed of high-quality sands as a result of an elevated level of wave activity. Reworking of barrier island sands was also found to be responsible for the enhanced reservoir quality. Consequently, regardless of the subsurface structure, the main driver of successful hydrocarbon accumulation is directly linked to the NW-SE trending paleoshoreline.

To the best of the authors’ knowledge, this is the first time forward-stratigraphic modeling is performed along the Jal Az-Zor escarpment in north Kuwait and using such an approach to unravel Kuwait Formation heavy hydrocarbon subsurface occurrences.
A Cognitive Data-Driven Single-Well Modeling Workflow for Reservoir Deliverability Predictions – Expanding the Wireline Formation Tester Application Envelope
Authors: Bari Abdul , Khan Mohammad Rasheed , Tanveer M. Sohaib , Hammad Muhammad , Adhami Asad Mumtaz , Siddiqi Sarmad S. , Zubair Talha , Ali Hamza , Sarili Mahmut , Ali Anwar , Abrar Saad Bin , Aziz Shahnawaz
Published: December 2021

In today's dynamically challenging E&P industry, exploration activities demand for out-of-the-box measures to make the most out of the data available at hand. Instead of relying on time consuming and cost-intensive deliverability testing, there is a strong push to extract maximum possible information from time- and cost-efficient wireline formation testers in combination with other openhole logs to get critical reservoir insight. Consequently, driving efficiency in the appraisal process by reducing redundant expenditures linked with reservoir evaluation. Employing a data-driven approach, this paper addresses the need to build single-well analytical models that combines knowledge of core data, petrophysical evaluation and reservoir fluid properties. Resultantly, predictive analysis using cognitive processes to determine multilayer productivity for an exploratory well is achieved.

Single Well Predictive Modeling (SWPM) workflow is developed for this case which utilizes plethora of formation evaluation information which traditionally resides across siloed disciplines. A tailor-made workflow has been implemented which goes beyond the conventional formation tester deliverables while incorporating PVT and numerical simulation methodologies. Stage one involved reservoir characterization utilizing Interval Pressure Transient Testing (IPTT) done through the mini-DST operation on wireline formation tester. Stage two concerns the use of analytical modeling to yield exact solution to an approximate problem whose end-product is an estimate of the Absolute Open Flow Potential (AOFP). Stage three involves utilizing fluid properties from downhole fluid samples and integrating with core, OH logs, and IPTT answer products to yield a calibrated SWPM model, which includes development of a 1D petrophysical model. Additionally, this stage produces a 3D simulation model to yield a reservoir production performance deliverable which considers variable rock typing through neural network analysis. Ultimately, stage four combines the preceding analysis to develop a wellbore production model which aids in optimizing completion strategies.

The application of this data-driven and cognitive technique has helped the operator in evaluating the potential of the reservoir early-on to aid in the decision-making process for further investments. An exhaustive workflow is in place that can be adopted for informed reservoir deliverability modeling in case of early well-life evaluations.
Development of Fracturing Technology for Deep Shale Gas in South Sichuan, China
Authors: Wang Haitao , Zhang Shikun , Bian Xiaobing , Li Shuangming , Tu Yulin , Zhang Xiong , Wang Zhifa
Published: December 2021

Under the condition of high ambient temperature and high confining pressure，the physical & mechanical properties and in-situ stress state of deep shale will change noticeably. Normally, the deep-shale formation has high horizontal stress difference (about 11∼21 MPa, 1595∼3045 psi), high fracture-closure pressure gradient (about 0.023∼0.025 MPa/m, 1.017∼1.105 psi/ft), high breakdown pressure gradient (larger than 0.03 MPa/m, 1.327 psi/ft), low mechanical brittleness (about 42%∼55%), low difference between the vertical and the horizontal stresses (about 3∼5MPa, 435∼725 psi). The complex geological characteristics of deep shale increase the difficulity of fracturing: 1) effect of brittle/ductile transition under high confining pressure; 2) non-uniform propagation of multi-cluster fractures is more prominent; 3) the migration of proppant is difficult in narrow fracture network; 4) high friction and high pumping pressure; 5) more stringent requirements for fracturing tools; 6) high requirements for fracturing scale, efficiency and economy.

To address above challenges, this paper presents a comprehensive overview of latest researching and applicable techniques about deep-shale fracturing (3500<TVD<3800 m, 11482∼12467 ft), including: 1) new evaluation methods on fractured shale quality and fracability, considering vertical stress difference coefficient and effective confining stress; 2) non-uniform propagation of fractures in multi-clusters perforation; 3) reveal the transport mechanism of proppant in narrow fracture network; 4) optimization of high performance fracturing fluid systems to enlarge the ESRV in deep shale; 5) development of a new staged fracturing tool for deep-shale fracturing, including dissoluble bridge plug and toe delayed sleeve; 6) an integrated geoscience and engineering simulation to optimize the treatment parameters and to achieve the best fracturing efficiency in the deep shale strata.

The hydraulic fracturing technique for deep shale gas with the depth of 3500∼4500 m (11482∼14763 ft) has formed preliminarily. The hydraulic fracturing technology for deep shale gas (TVD≥3500∼3800 m, 11482∼12467 ft) have made a breakthrough in Sichuan basin, China, and significant progress has also made in 3800-4500m TVD (12467∼14763 ft). The research results and techniques introduced in the paper have been successfully applied to more than 100 wells in the Sichuan basin. The test production of part fractured well can reach (10∼31)×104 m3 per day (0.35∼1.09×107 SCF/day), which basically realizes the economical and effective development for deep shale gas.
An Alternative Tool for Production Logging in Horizontal Wells
Authors: Husein Nadir , Xu Jianhua , Novikov Igor , Gazizov Ruslan , Buyanov Anton , Wang Guangyu , Lysova Dina , Upadhye Vishwajit
Published: December 2021

From year to year, well drilling is becoming more technologically advanced and more complex, therefore we observe the active development of drilling technologies, well completion and production intensification. It forms the trend towards the complex well geometry and growth of the length of horizontal sections and therefore an increase of the hydraulic fracturing stages at each well. It's obvious, that oil producing companies frequently don't have proved analytical data on the actual distribution of formation fluid in the inflow profiles for some reasons. Conventional logging methods in horizontal sections require coiled tubing (CT) or downhole tractors, and the well preparation such as drilling the ball seat causing technical difficulties, risks of downhole equipment getting lost or stuck in the well. Sometimes the length of horizontal sections is too long to use conventional logging methods due to their limitations.

In this regard, efficient solution of objectives related to the production and development of fields with horizontal wells is complicated due to the shortage of instruments allowing to justify the horizontal well optimal length and the number of MultiFrac stages, difficulties in evaluating the reservoir management system efficiency, etc.

A new method of tracer based production profiling technologies are increasingly applied in the global oil industry. This approach benefits through excluding well intervention operations for production logging, allows continuous production profiling operations without the necessity of well shut-in, and without involving additional equipment and personal to be located at wellsite.
The Effect of High Power Laser on Organic-Rich Shales
Authors: San Roman Alerigi Damian , Batarseh Sameeh , Assiri Wisam
Published: December 2021

The objective of this work is to characterize the effect of a high power laser (HPL) on organic-rich shales. The analysis combines machine learning with advanced characterizations to reveal the geochemical and mechanical transformations induced by high power laser in source rocks. Lab results showed that HPL improves permeability, increases porosity, modifies the mechanical structure of the rock, and may positively affect the maturity of source rocks.

A high power laser was used in the lab to perforate and heat different types of source rocks with varying organic content. The process was characterized in real time using near-infrared spectroscopy and mid-IR thermography. The pre- and post-characterization process draws on different tools to evaluate the chemical and structural transformations induced by the HPL processes. This step included several spectroscopy techniques (e.g., FTIR, UV/VIS/NIR), Rock-Eval, and differential thermal analysis (DTA). The analysis leverages on clustering techniques to reveal the distinct effects of HPL on source rocks.

The spectroscopy and geochemical analyses revealed that that HPL modifies the molecular structure of the rock. Yet, the fundamental structure of the rock remains intact. The changes are revealed by clustering analysis of the FTIR data before and after laser heating. The analysis show the formation of clusters after the process, which correspond to the maturation of the organic content.

The success of the lab work proved that high power laser could enhance the properties of source rocks. The effects include permeability improvement, enhanced porosity, and changes in the molecular distribution of the organic content. The results of the analyses suggest that the laser can drive forward the maturity of the source rock. This work also illustrates how machine learning and multiphysics characterization can reveal the dynamics of the HPL processes and their effects. Ultimately, the outcome of this study will contribute to the development of novel HPL applications.
The Internet of Sensors IoS in Oil and Gas Industry
Authors: Alalouni Ahmed , Saeed Abubaker , Arsalan Muhammad
Published: December 2021

In a highly sensitivity oil and gas upstream conditions, there is a need for a real-time interaction platform to cope with harsh environment. The oil and gas business faces data validity constraints in terms of reliability, accuracy, and repeatability to name a few. The Internet of Sensors (IoS), with appropriate utilization, will play a major role in the industry's digital transformation.

Predetermined IoS platforms with applicable characteristics are functioning in critical oil and gas environment applications. For example, some oil and gas wells produces harmful gases, like hydrogen sulfide (H2S). Fiber-optic sensors can be used as a leak detection tool for H2S resistance to inform oil and gas curfew if harmful gas is detected at the well site using cloud computing. Scale and corrosion monitoring of external pipelines is one of the integrity challenges. Ultrasonic sensors are embedding for real-time scale thickness feedback and corrosion monitoring by utilizing wireless transmission directly to end-user devices.

A paradigm shift is happening with the IoS applications in oil and gas operations for sensitivity, reliability, and accuracy that will add intelligence, smart decisions, and control to the operational landscape. A comprehensive review of the art in oil and gas IoS presented in this paper. The target is to evaluate state-of-the-art IoS platforms for hazardous environments such as oil and gas facilities in terms of type of sensors used, applicability, functionalities, linearity, and accuracy, type of output signals, outputs range, and materials used. This work establishes classification and comparison of the IoS for better data collection, communication, connectivity, observation, and reporting in the world of oil and gas sensors. The IoS platforms classified and compared in tables consisting of different characteristics for the best-suited IoS platform designs in oil and gas appliance applications. This will provide references for IoS design engineers.
An Advanced Ultra-Deep Resistivity Mapping Sensor Reduced Reservoir Uncertainty and Eliminated the Need for a Pilot Hole for the First Time; A Case Study from Offshore Abu Dhabi
Authors: Fares Wael , Moustafa Islam , Al Felasi Ali , Khemissa Hocine , Al Mutwali Omar , Gutierrez Freddy , Clegg Nigel , Duriez Alban , Aki Ahmet
Published: December 2021

The high reservoir uncertainty, due to the lateral distribution of fluids, results in variable water saturation, which is very challenging in drilling horizontal wells. In order to reduce uncertainty, the plan was to drill a pilot hole to evaluate the target zones and plan horizontal sections based on the information gained. To investigate the possibility of avoiding pilot holes in the future, an advanced ultra-deep resistivity mapping sensor was deployed to map the mature reservoirs, to identify formation and fluid boundaries early before penetrating them, avoiding the need for pilot holes.

Prewell inversion modeling was conducted to optimize the spacing and firing frequency selection and to facilitate an early real-time geostopping decision. The plan was to run the ultra-deep resistivity mapping sensor in conjunction with shallow propagation resistivity, density, and neutron porosity tools while drilling the 8 ½-in. landing section. The real-time ultra-deep resistivity mapping inversion was run using a depth of inversion up to 120 ft., to be able to detect the reservoir early and evaluate the predicted reservoir resistivity. This would allow optimization of any geostopping decision.

The ultra-deep resistivity mapping sensor delivered accurate mapping of low resistivity zones up to 85 ft. TVD away from the wellbore in a challenging low resistivity environment. The real-time ultra-deep resistivity mapping inversion enabled the prediction of resistivity values in target zones prior to entering the reservoir; values which were later crosschecked against open-hole logs for validation. The results enabled identification of the optimal geostopping point in the 8 ½-in. section, enabling up to seven rig days to be saved in the future by eliminating a pilot hole. In addition this would eliminate the risk of setting a whipstock at high inclination with the subsequent impact on milling operations. In specific cases, this minimizes drilling risks in unknown/high reservoir pressure zones by improving early detection of formation tops. Plans were modified for a nearby future well and the pilot-hole phase was eliminated because of the confidence provided by these results.

Deployment of the ultra-deep resistivity mapping sensor in these mature carbonate reservoirs may reduce the uncertainty associated with fluid migration. In addition, use of the tool can facilitate precise geosteering to maintain distance from fluid boundaries in thick reservoirs. Furthermore, due to the depths of investigation possible with these tools, it will help enable the mapping of nearby reservoirs for future development. Further multi-disciplinary studies remain desirable using existing standard log data to validate the effectiveness of this concept for different fields and reservoirs.
Multi-Objective Optimisation Analysis for Off-Grid, On-Site Power Generation Comparing Hybrid Renewable Energy Systems and Gas-to-Power Systems In Upstream Applications
Authors: Ruvalcaba Velarde Salvador Alejandro
Published: December 2021

As the oil and gas industry increases its focus on sustainability, including greenhouse gases emissions reductions and carbon footprint management, it is relevant to analyze optimal solutions integrating different renewable, green and hydrogen technologies into hybrid renewable energy systems and compare them with well gas-to-power approaches for off-grid, on-site power generation in upstream applications.

This paper goes through a desk review of different types of upstream facilities and an overview of potential power requirements to consider for off-grid electrification. Then, different technologies used for off-grid hybrid renewable energy systems are introduced and compared in terms of potential uses and integration requirements. Furthermore, emission targets are presented along with potential economical constraints. With those aspects introduced, system sizing and assumptions are modeled, simulated and optimized.

The different modeled cases, including integrated renewable energy systems and power-to-gas systems, are presented in terms of suitability in application to the facilities under consideration. For such cases, simulation results are presented in quantitative terms of equivalent optimized value for the multiple competing objectives in the study, in terms of sustainability targets and economics. Sensitivity analysis are also presented showing main parameters of influence on the optimal energy scheme approach.

This paper provides a qualitative and quantitative analytical optimization approach evaluating multiple competing objectives in terms of green, renewable, hydrogen and gas-to-power technologies, economics and carbon footprint management for consideration in facilities power systems schemes.
Carbon Emission Reduction via HNGLRP CC&S Technology
Authors: Ahmari Sultan , Mufti Abdullatef
Published: December 2021

The paper objective is to present the successful achievement by Saudi Aramco gas operations to reduce the carbon emission at Hawyiah NGL Recovery Plant (HNGLRP) after successful operation & maintainability of the newly state of the art Carbon Capture & Sequestration (CC&S) technology. This is in line with the Kingdom of Saudi Arabia (KSA) 2030 vision to increase the resources sustainability for future growth and part of Saudi Aramco circular economy in action examples.

Saudi Aramco CC&S started in June 2015 at HNGLRP with main objective to capture the carbon dioxide (CO2) from Acid Gas Removal Units (AGRUs) and then inject an annual mass of nearly 750 Kton of carbon dioxide into oil wells for sequestration and enhanced oil recovery maintainability. This is to replace the typical acid gas incineration process after AGRUs operation to reduce carbon footprint. CC&S consists of the followings: integrally geared multistage compressor, standalone dehydration system using Tri-Ethylene Glycol (TEG), CO2 vapor recovery unit (VRU), Granulated Activated Carbon (GAC) to treat water generated from compression and dehydration systems for reuse purpose, and special dense phase pump that transfers the dehydrated CO2 at supercritical phase through 85 km pipeline to replace the typical sea water injection methodology in enhancing oil recovery. CC&S has several new technologies and experiences represented by the compressor capacity, supercritical phase fluid pumping, using mechanical ejector application to maximize carbon recovery, and CO2/TEG dehydration system as non-typical dehydration system. CC&S design considered the occupational health hazards generated from the compressor operation by installing engineering enclosure with proper ventilation system to minimize the noise hazard. CC&S helped HNGLRP to reduce the overall Greenhouse Gas (GHG) emission resulted from typical CO2 incineration process (thermal oxidizing). (2)

The total GHG resulted from combustion sources at HNGLRP reduced by nearly 30% since CC&S technology in operation. The fuel gas consumption to run the thermal oxidizers in AGRUs reduced by 75% and sent as sales gas instead. The Energy Intensity Index (EII) reduced by 8% since 2015, water reuse index (WRI) increased by 12%. In conclusion, the project shows significant reduction in the carbon emission, noticeable increase in the production, and considerable water reuse.
Pilot Project: Application of Multi-Component Thermal Fluid Stimulation on Shallow Heavy Oil Reservoir in Kazakhstan
Authors: Yi Leihao , Hua Xin , Guan Wenlong , Xu Shiguo , Zhang Ziyi , Mei Yizhong , Guo Erpeng , Liu Junping , Zhong Li , Liu Guohui , Zheng Xiantao , Wei Zhen
Published: December 2021

Cyclic steam simulation (CSS) was widely used to recover heavy oil in shallow reservoirs in Kazakhstan. In the late stage of CSS in M oilfield, the performance of this CSS project was poor with high water cut and low oil steam ratio (OSR), indicating low economic benefit. The multi-component thermal fluid (MTF) stimulation trial has been conducted there since March 2018 to evaluate the feasibility of this technology.

This paper introduces the field experience and the production performance of MTF stimulation. Results are from 32 cycles of MTF stimulations in 23 wells, most of which had completed their 4 cycles of CSS before.

MTF technology is based on a high-pressure jet combustion mechanism, generating a mixture of nitrogen, carbon dioxide and vapor (MTF) under a sealed combustion condition. The mixture fluid provides a significant enhancement through a synergistic effect in the reservoir. The soaking and recovery process are the same as the conventional steam stimulation, meanwhile the requirements for completion and wellbore structure are the same as well. By the time of statistic, average cyclic OSR reaches 2.19 from 0.49 of last CSS cycle. Average water cut declines from 90% to 40% and daily oil production rises from 22 bbls to 33 bbls. Free water is almost invisible in the produced fluid, instead, a stable quasi-monophasic flow has been presented even at low temperatures. This effectively increases the fluidity and dilatancy of crude oil, and greatly replenishes the elastic energy of the formation. Meanwhile, with all components injected into the formation, MTF stimulation achieves significant reduction in carbon emissions.

Although this is a pilot test, considerable economic benefits have been achieved with the increase of oil production efficiency. MTF stimulation brings an additional profit of USD 4.4 million for the first year under conditions of local material's cost. This successful pilot demonstrates that MTF stimulation may play an important role at late stage of CSS, even it has its own prospect in an initial heavy oil reservoir development. In the meantime, this pilot experience can be used as a reference for other similar reservoirs’ development.
Manganese Assisted Waterflooding Processes for Enhanced Oil Recovery in Carbonates
Authors: Alghamdi Amani , Salah Saleh , Otaibi Mohammed , Ayirala Subhash , Yousef Ali
Published: December 2021

Modifying the wettability of carbonate formations through divalent foreign metal incorporation can become a cost-effective practical method for enhanced oil recovery (EOR) applications. The addition of manganese ions to both high salinity water (HSW) and tailored SmartWater at dilute concentrations is exploited in this study to maximize the interfacial potential and promote water-wet conditions in carbonate reservoirs.

In this experimental investigation, the impact of manganese ions on zeta-potentials at calcite/brine and crude oil/brine interfaces is first determined by measuring zeta-potentials in calcite suspensions and oil emulsions. Two different water chemistries representative of HSW (~60,000 ppm TDS) and a low salinity tailored SmartWater (~6,000 ppm TDS) were used. The measurements were then extended to carbonate rocks and reservoir cores by performing contact angle and spontaneous imbibition tests at reservoir conditions. The oil-water interfacial tensions are also measured to understand the interactions of manganese ions at the oil/brine interface.

The zeta potential results showed a positive consistent trend, with the addition of 100-1,000 ppm of Mn+2 ions in the form of MnSO4 to the high salinity water, to impact the wetting transition towards water-wet conditions in carbonates. The addition of Mn+2 ions at a concentration of 100-1,000 ppm to HSW enhanced the electrokinetic interactions to favorably alter surface charges at both oil/brine and calcite/brine interfaces. These findings based on eletrokinetic interactions demonstrated good agreement with contact angle data wherein manganese ions in HSW were able to drastically decrease the contact angles from 156 to 88°. Conversely, insignificant changes in oil-water interfacial tensions were observed due to manganese ions. The manganese assisted spontaneous imbibition oil recoveries were increased by about 10% in HSW. Mn+2 ions showed the ability to increase the negative potentials at both calcite/brine and oil/brine interfaces. The obvious trend of such enhanced electrical potential due to Mn+2 addition at the calcite interface supports the claim that Mn+2 selectively gets incorporated into the calcite crystal to modify its surface chemistry. This is expected to increase the surface charges of same polarity at the two opposing interfaces and promote the electrostatic repulsion to inherently change the surface preference towards water-wet conditions.

This work for the first time identified the favorable impact of incorporating Mn+2 ions under optimized conditions to enhance the wetting transition in carbonate reservoirs. Such new knowledge gained from this experimental study highlights the practical significance of Mn+2 ions as cheap and sustainable wettability modifiers for EOR applications in carbonate reservoirs.
Quick-Look Water Saturation Estimate with Density-Neutron Logs in Unknown or Mixed Salinity Environments: Case Studies in Middle East Oil-Bearing Carbonate Reservoirs
Authors: Cao Minh Chanh , Jain Vikas , Maggs David , Gzara Kais
Published: December 2021

We have shown previously that while total porosity is the weighted sum of density and neutron porosities, hydrocarbon volume is the weighted difference of the two. Thus, their ratio yields hydrocarbon, or equivalently, water saturation (Sw). In LWD environments where negligible invasion takes place while drilling, we investigate whether Sw derived from LWD density-neutron logs could approach true Sw in unknown or mixed water salinity environments.

In such environments, it is well known that Sw determined from standalone resistivity or capture sigma logs is uncertain due to large water resistivity (Rw) or capture sigma (Σw) changes with salinity. On the other hand, the water density (ρw) and hydrogen index (HIw) variations with salinity are much less (Table 1). Hence, the water point on the density neutron crossplot does not move with salinity as much as the water point on a sigma-porosity crossplot does. Similarly, the water point on a resistivity-porosity Pickett plot would move drastically with changes in Rw.

Also, because the hydrocarbon effect on density-neutron logs is much less in oil than in gas, the weights in the density-neutron porosities can be conveniently set at midpoint in light oil-bearing reservoirs without compromising porosity and saturation results. Thus, a quicklook estimate of Sw from density-neutron logs is the normalized ratio of the difference over the sum of density and neutron porosities. The normalization factor is a function of the hydrocarbon density. We also build a graphical Sw overlay for petrophysical insights.

We tested the LWD density-neutron derived Sw in two Middle East carbonate oil wells that have mixed salinity. The two wells were extensively studied in the past. In the first well, the reference Sw is given by the joint-inversion of resistivity-sigma logs, corroborated with Sw estimated from multi-measurements time-lapsed analysis, and validated with water analysis on water samples taken by formation testers. In the second well, comprehensive wireline measurements targeting mixed salinity such as dielectric and 3D NMR were acquired to derive Sw, and complemented by formation tester sampling, core measurements, and LWD resistivity-sigma Sw. In both wells, density-neutron quicklook Sw agrees surprisingly well with Sw from other techniques. It may lack the accuracy and precision and the continuous salinity output but is sufficient to pinpoint both flooded zones and bypassed oil zones.

Since density-neutron is part of triple-combo data that are first available in well data acquisition, it is recommended to go beyond porosity application and compute water saturation (Sw) in unknown or mixed salinity environments. The computation is straightforward and can be useful to complement other established techniques for quick evaluation in unknown or mixed water salinity environments.
Modified Carbon Dots with Lowered Retention and Improved Colloidal Stability for Application in Harsh Reservoir Condition
Authors: Wang Wei
Published: December 2021

Tracer technology has been increasingly used in inter-well tests to investigate reservoir performance, reservoir connectivity and residual oil saturation for providing useful information to improve decision making in reservoir management. Stable nanoparticle tracers with high-sensitive real-time detectability are highly desired, and as one of the nanoparticles tracers, carbon dots (C-dots) have been studied and tested as nano-agent tracer in field trial for reservoir monitoring. In this research, we report a modified method to synthesize fluorescent C-dots and fluorinated, sulfonated or zwitterionic functional groups were incoprtated into the C-dots. The synthesis reaction occurs at hydrothermal conditions with inexpensive starting materials and is readily to scale up for industrial application. Optical properties of the synthesized colloidal C-dots were studied by UV-visible and fluorescence spectroscopies. Colloidal stability was studied by dynamic light scattering (DLS) measurements, and retention of the C-dots in porous medium was evaluated by adsorption experiment with limestone rock. The synthesized C-dots are readily dispersible in freshwater and synthetic brines and exhibit improved colloidal stability in hot brine and lowered retention in reservoir rocks. In comparison with those C-dots reported in literatures, our results suggest that the synthesized C-dots using the modified procedure have excellent fluorescence properties, improved thermal stability, photostability, and water dispersibility, enabling their use as optically detectable nano-agent tracer in oil field application.
Successful Case Study of Machine Learning Application to Streamline and Improve History Matching Process for Complex Gas-Condensate Reservoirs in Hai Thach Field, Offshore Vietnam
Authors: Hoang Son , Tran Tung , Nguyen Tan , Truong Tu , Pham Duy , Tran Trung , Trinh Vinh , Ngo Anh
Published: December 2021

This paper reports a successful case study of applying machine learning to improve the history matching process, making it easier, less time-consuming, and more accurate, by determining whether Local Grid Refinement (LGR) with transmissibility multiplier is needed to history match gas-condensate wells producing from geologically complex reservoirs as well as determining the required LGR setup to history match those gas-condensate producers.

History matching Hai Thach gas-condensate production wells is extremely challenging due to the combined effect of condensate banking, sub-seismic fault network, complex reservoir distribution and connectivity, uncertain HIIP, and lack of PVT data for most reservoirs. In fact, for some wells, many trial simulation runs were conducted before it became clear that LGR with transmissibility multiplier was required to obtain good history matching. In order to minimize this time-consuming trial-and-error process, machine learning was applied in this study to analyze production data using synthetic samples generated by a very large number of compositional sector models so that the need for LGR could be identified before the history matching process begins. Furthermore, machine learning application could also determine the required LGR setup. The method helped provide better models in a much shorter time, and greatly improved the efficiency and reliability of the dynamic modeling process.

More than 500 synthetic samples were generated using compositional sector models and divided into separate training and test sets. Multiple classification algorithms such as logistic regression, Gaussian Naive Bayes, Bernoulli Naive Bayes, multinomial Naive Bayes, linear discriminant analysis, support vector machine, K-nearest neighbors, and Decision Tree as well as artificial neural networks were applied to predict whether LGR was used in the sector models. The best algorithm was found to be the Decision Tree classifier, with 100% accuracy on the training set and 99% accuracy on the test set. The LGR setup (size of LGR area and range of transmissibility multiplier) was also predicted best by the Decision Tree classifier with 91% accuracy on the training set and 88% accuracy on the test set. The machine learning model was validated using actual production data and the dynamic models of history-matched wells. Finally, using the machine learning prediction on wells with poor history matching results, their dynamic models were updated and significantly improved.
A Successful Application of Continuous Pack-Off Technology to Water Shutoff Recompletion for High-WCT Gravel-Packed Horizontal Well
Authors: Jiang An , Li Yunpeng , Liu Xing , Zhang Fengli , Wang Tianhui , Liu Yuezhong , Han Lianhe , Pei Bailin , Chen Yingying
Published: December 2021

Objectives/Scope

Controlling the excessive water production from the high water cut gravel packing horizontal well is a challenge. The approach which uses regular packers or packers with ICD screens to control the unwanted water does not function well. This is mainly because of the length limitation of packers which will make the axial flow resistance insufficient.

Methods, Procedures, Process

In this paper, a successful case that unwanted water is shutoff by using continuous pack-off particles with ICD screens (CPI) in the whole horizontal section in an offshore oilfield of Bohai bay is presented. The reservoir of this case is the bottom-water high viscosity reservoir. The process is to run 2 3/8" ICD screen string into the 4" screen string originally in place, then to pump the pack-off particles into the annulus between the two screens, and finally form the 360m tightly compacted continuous pack-off particle ring.

Results, Observations, Conclusions

The methodology behind the process is that the 2-3/8" ICD screens limit the flow rate into the pipes as well as the continuous pack-off particle ring together with the gravel ring outside the original 4" screens to prevent the water channeling into the oil zone along the horizontal section. This is the first time this process is applied in a high water cut gravel packed horizontal well. After the treatment, the water rate decreased from 6856BPD to 836.6BPD, the oil rate increased from 44BPD to 276.8BPD. In addition, the duration of this performance continued a half year until March 21, 2020.

Novel/Additive Information

The key of this technology is to control the unwanted water by using the continuous pack-off particles instead of the parkers, which will bring 5 advantages, a) higher efficiency in utilizing the production interval; b) no need to find the water source and then fix it; c) the better ability to limit the axial flow; d) effective to multi-WBT (water break though) points and potential WBT points; e) more flexible for further workover. The technology of this successful water preventing case can be reference to other similar high water cut gravel packed wells. Also, it has been proved that the well completion approach of using CPI can have good water shutoff and oil incremental result. Considering the experiences of historical applications, CPI which features good sand control, water shutoff and anti-clogging is a big progress compared to the current completion technologies.