bluuebunny/crossref_metadata_2025_split huggingface dataset:
Qualification of Downhole Valves Used in Continuous Injection Systems
Authors: Stewart-Liddon Christine , Goodwin Neil J , Graham Gordon M , Tjomsland Tore , Hustad Britt Marie , Svela Odd Geir , Olsen John Helge , Østgaard Simon 
Published: February 2021

Abstract
Downhole Continuous Chemical Injection (DCI) systems, including both Downhole Continuous Injection systems (DHCI) and Gas Lift Chemical injection (GLI) are increasingly being installed in new wells for the application of a range of chemicals. These systems have one or more check valves at the point of injection to control the chemical flow into the wellbore and prevent wellbore fluids from entering the injection lines. In-line filters are included to remove particulates that may prevent the check valves from sealing.
The performance of the injection valves is key to the success of continual injection systems. Valve failure would lead to uncontrolled injection into the wellbore, forming low pressure gas pockets within the injection lines which can lead to changes in the physical properties of the chemical causing issues such as corrosion or gunking. In addition, if the hydrostatic pressure within the injection line drops below wellbore pressure, then wellbore fluids can start to enter the capillary tubing.
Currently, the qualification of valves is conducted using either fresh water or nitrogen. In conjunction with considerable developments made in qualification of chemicals for DHCI and GLI which were introduced in previous papers1, 2, work has been undertaken to improve the qualification of the injection system itself. This means that in addition to showing compatibility and good performance, the chemical must be suitable for the application system, and the equipment suitable for the chemical selected. Results demonstrate how different valve/chemical combinations can perform well during fluid injection but fail to hold pressure within the injection line when the flow is stopped.
The paper will present results from an extensive series of valve tests conducted in a newly designed and commissioned rig capable of operating at full reservoir temperatures (up to 200 °C) and elevated line pressures (up to 5,000 psi). The results from this work are expected to form the basis of a new range of system qualification protocols to be proposed for Statoil DHCI systems.
An Advanced Method for Preparing Ferrous Sulfide and Testing Potential Inhibitors
Authors: Fowles Robert G. , Levey Simon J.M. , Smith Clayton S. 
Published: February 2021

Abstract
Ferrous-sulfide (iron II sulfide) scale typically forms in the wellbore under anaerobic conditions and may cause a reduction in well productivity. It has been proposed that ferrous ions react with bisulfide formed from dissolved hydrogen sulfide to form a complex iron bisulfide intermediate, which further reacts to produce black solid ferrous sulfide. Treatment of this type of scale typically involves mineral acids or chelants, which themselves provide additional challenges for pipeline integrity.
The Weatherford flow assurance laboratory carries out tests that determine the best inhibitors for scale problems. Compared to calcite, barium, and gypsum scales, little work has been done to study prevention of ferrous sulfide scale. For calcite, barium, and gypsum scales, the dynamic-flow loop is commonly used. However, for ferrous-sulfide scale, there is a challenge for a quick and reliable test method. The preparation of ferrous sulfide under sour conditions is not straight forward due to both the difficulty in achieving sufficiently anaerobic conditions and the associated hazards of managing H2S. The presence of oxygen will result in ferric sulfide instead of ferrous sulfide.
This paper describes in detail laboratory experiments to safely prepare ferrous sulfide scale using H2S and also test potential inhibitors. Comparisons were made between using metal sulfide instead of H2S. Using the H2S method to prepare ferrous sulfide provided a quick and robust way to select potential inhibitors under various conditions, which can be used to improve flow assurance assessments.
This paper will demonstrate selected chemicals compared to tetrakis (hydroxymethyl) phosphonium sulfate (THPS) in preventing the formation of ferrous sulfide under sour conditions and ambient or elevated pressures and temperatures when applied at low concentrations. Some inhibitors that are successful under sour ferrous sulfide preparations are not effective when metal sulfide ions are used instead of H2S, which means potential inhibitors are being missed due to inappropriate test methods.
Overall, a technological advancement was made with an anaerobic and sour method to test effectively ferrous sulfide inhibitors that would perform at low concentrations.
New Methodologies for Human Factors in Process Safety
Authors: James B. 
Published: February 2021

Abstract
Process Safety has been a major focus for the Oil and Gas and Petrochemical industries since the Flixborough disaster of 1974. Through the efforts of leaders in Safety there have been a number of key methodologies that has assisted Process Safety professionals in identifying “what went wrong” and how do we learn from disasters to prevent similar incidents from occurring again. Industry professional Dr. Trevor Kletz has gone as far as saying “Organisations have no Memory” Kletz (1993). However, over the last few decades, the industry seems to be making the same mistakes every few years. Research, insight and well-structured root cause analysis has highlighted that Human Factors and Organisational Culture is an area that must be considered in understanding Process Safety related incidents. Organisations such as the Centre for Chemical and Process Safety has included Human Factors as one of the elements in the Management System for Process Safety. System thinking and system dynamics has been identified a way of thinking about and analysing Process Safety related incidents to understand the Human Factor and its role in process related incidents.
Achieving Long Term Well Integrity: An Engineered Solution for Production Casing in a Deepwater Environment
Authors: Reveth V. , Giron Rojas R. , Gupta N. , Gonzaga E. 
Published: February 2021

Abstract
In a deepwater environment, any remedial operation has a high impact on the overall costs during the life of the wells. The zonal isolation can be compromised due to the exposure of the well's main components (casing and cement) to the changes in the stress conditions. The changes in wellbore conditions can occur during the drilling, production, intervention, and decommissioning stages. Typically, conditions such as fluid pathway and high formation pressure are sufficient to lose zonal isolation. The fluid pathway can be a fissure, an induced crack in the cement sheath, a mud channel, a micro-microannulus, or changes in the cement matrix permeability. As a result of the oil industry technology developments, progresses, the advanced stress-modelling software and the availability of cement and rock properties property data have enabled to an improved understanding of the cement behavior under stress. Prevention of the loss of the hydraulic isolation provided by the primary cementing in the annulus can be assessed by predicting the mechanical failure of the cement sheath. Formation geo-mechanics is one of the main factors that help in designing a robust cement system for changing stresses. Furthermore, the consequence result of the cement sheath failure can be mitigated by the placement of placing a self-healing cement (SHC) system to maintain long-term zonal isolation.
An interdisciplinary approach can be used to determine the following: Understand the impact of the well plan, and fluid densities on well integrity, in addition to cementing best practices.Characterize typical deepwater field formations, and establish limits for geo-mechanical values of each layer.Identify critical factors and focus on the pay zones.Understand potential issues and communication between the pay zones and the aquifers that are already previously confirmed.Determine risk of zonal communication assessment, mitigation, and prevention measurement implementations
Once the formation data is validated by the operator, the life cycle of the well is simulated and the risk of zonal isolation can be evaluated. The results of this assessment can help the operator choose between to take the approach of mitigation, prevention, or a combination of both. The objective is to place a robust cement sheath with advanced mechanical performance in the pay zones that can resist the failures due to changing stresses during the well testing and production. This paper uses presents examples from a deepwater development field to show how cement systems with advanced mechanical properties counter the critical stresses during the lifecycle of a well and maintain zonal isolation.
A Fundamental Model for Predicting Oil Recovery Due to Low Salinity Water Injection in Carbonate Rocks
Authors: Al-Shalabi E. W. , Sepehrnoori K. , Pope G. , Mohanty K. 
Published: February 2021

Abstract
The low salinity water injection (LSWI) technique is gaining popularity due to the simplicity of the method compared to other thermal and chemical EOR techniques. In this paper, a fundamental model is proposed which captures the effect of LSWI on improving the microscopic displacement efficiency from carbonates through the trapping number. The proposed model was used to history match recently published corefloods using the UTCHEM simulator. The proposed model incorporates wettability alteration effect through contact angle and trapping parameter. Results showed that history matching of the corefloods was performed successfully using the proposed model. Moreover, wettability alteration is the main contributor to LSWI effect on oil recovery from carbonate rocks. The proposed model was further validated upon which the applicability is extended to include weakly-oil-wet to mixed-wet rocks. This model can be used for oil recovery predictions from carbonate rocks at the field-scale.
Geomechanics: a New Star in the Horizon to Change the Fortunes in E&P Projects
Authors: Hegazy M. , Lakshmikantha M.R. 
Published: February 2021

Abstract
The E&P industry all over the world is awakening to the new technology discipline of Geomechanics, recognizing its importance in every operation of hydrocarbons exploitation, from drilling to production. There are specific applications in the early stage of exploitation, e.g. with respect to wellbore stability, sand production, hydraulic fracturing, traversing depleted zones, characterization of fractures and fault sealing capacity. In the later stages of production it can better characterize reservoir subsidence and fracture behavior with pressure evolution. A rigorous application of these methods can add important value to E&P projects. The need for innovative ways to solve the technology challenges planted the seeds of Geomechanics to germinate and grow as a key technology in E&P industry with applications for present and future projects. The vision for the future of this emerging discipline is bright with strong growth in applications. It is especially relevant to meet the challenges posed by many new discoveries, especially unconventional plays, which are often difficult to develop profitably. Geomechanics creates opportunities for improved and integrated project management. It can offer a variety of solutions by integrating conventional E&P technologies with cutting edge numerical, mathematical models that impacts the reservoir production behavior. Major operators were the first to embrace the scientific use of Geomechanics to help develop difficult reservoirs profitably. Also, a few medium-sized oil companies have recognized this potential and, as a consequence, have created Geomechanics teams with in. In this article, the authors provide a bird's eye view of Geomechanics as a core E&P technology supporting mega E&P projects. We discuss the current state of the art of this technology, with special emphasis on applications.
Feasibility Study on the Implementation of CO2-EOR Coupled with Sequestration in Trinidad via Reservoir Simulation
Authors: Narinesingh J. , Boodlal D. V. , Alexander D. 
Published: February 2021

Abstract
The paper seeks to assess the technical and economic feasibility of implementing carbon dioxide enhanced oil recovery (CO2 EOR) in Trinidad and Tobago from flue gas production whilst mitigating the effect of greenhouse gases via CO2 sequestration. An existing power plant in Trinidad was selected as the CO2 source. As such, actual CO2 volumes and properties were found and used in this analysis. However, a hypothetical field was chosen as the appropriate sink, which can be analogous to a field in onshore Trinidad.
A detailed reservoir model was built using the compositional fluid model CMG-GEM. Various scenarios were simulated to determine the optimum number of producers for primary production and the best location of the injectors for CO2 EOR. The optimum number of producers for the reservoir during primary production was found. In addition, the most favorable location of the injector to avoid early breakthrough and increase oil recovery was also determined.
Many key parameters were reported from this investigation. These included OIIP, forecasted production and primary recovery. After primary production, CO2 EOR was then implemented with the use of the reservoir and fluid models and the additional recovery is reported. Other Key CO2-EOR parameters such as CO2 utilization rate and total sequestered CO2 were also quantified.
Though a hypothetical reservoir was used, all associated data were defined and once an actual reservoir is known, the same technically rigid methodology can be applied.
The OIIP was found to be 6.74 MMSTB for the selected reservoir. Based on an economic net present value (NPV) assessment, the optimum number of production wells for field development was found to be 3. At the end of primary production from these three wells (with 2.375 in. tubing), a total of 1.83 MMSTB were produced. This corresponded to a primary recovery factor of 27.2% over 4 years and 2 months.
For CO2 EOR coupled with sequestration, these three wells were manipulated and used as 1 injector and 2 producers. CO2 EOR led to another 1.07 MMSTB of recovery for a total of 2.9 MMSTB (43.04% Recovery) for the ten year life of the project. A total of 5427 MMSCF (287 000 tons) of CO2 was sequestered in the reservoir (40.39% Storage) at an injection pressure of 1400 psi.
The Analysis and Interpretation of Parameters on Well Performance of Low Permeability Water-Producing Reservoirs: a Case Study of Daniudi Gas Field
Authors: Li Y. , Li X. , Shi J. , Wang H. , Wu L. , Xu D. , Teng S. 
Published: February 2021

Abstract
Predicting the effects of reservoir and well parameters on the performance of multi-fractured horizontal wells in low-water-producing reservoirs is very important in determining which operations should be taken for improving the gas recovery. Due to the increased number of horizontal wells drilled in Daniudi gas field, there is a necessity for a better and improved understanding of the behavior and performance.
In this case, a linear regression model approaches for developing prediction the performance from well data of Daniudi gas field. The linear regression model has been developed relationships among the performances, reservoir and well parameters. The results show that the performances are not only functions of permeability, pressure drops, gas saturation, number of fractures, length of horizontal well, but also related with some special parameters such as drilling-encounter rate, flowback rate, water gas ratio. Additionally, the linear regression model is corrected by considering the problem of liquid loading. Finally, the sensitivity analyses of these parameters have been studied and the parameters have been ordered according to the degree of sensitivity. This study is very important for understanding the main influence parameters on the performance in Daniudi gas field, which play a significant role for further operations to improving the performances.
Investigation of Significance of Critical Components in Optimization of WAG Injection Processes under Uncertainty
Authors: Temizel C. , Purwar S. , Agarwal A. , Abdullayev A. , Urrutia K. , Chacon-Garcia A.J. 
Published: February 2021

Abstract
Water alternating gas (WAG) injection has been widely used for the last 50 years throughout the world. The typical improved oil recovery (IOR) potential for WAG injection compared with water injection is 5 to 10%. It was originally intended to improve sweep efficiency during gas flooding, with intermittent slugs of water and gas designed to follow the same route through the reservoir. Mechanisms in WAG injection include microscopic effects, particularly in cases where three-phase flow and hysteresis are important for the IOR effect. Injection of gas usually aids an ongoing waterflood, and finding technical and commercial methods to reduce gas costs would be useful. Water injection alone tends to sweep the lower parts of a reservoir, while gas injected alone sweeps more of the upper parts of a reservoir because of gravitational forces. Gas represents a large fraction of the total cost, making WAG injection an expensive method. Thus, optimizing WAG injection is not only crucial in terms of recovery but also economics, especially where gas is expensive and/or limited. In this study, the significance of key components in a WAG injection process on SPE's 5th Comparative Solution Project (CSP) is presented that models the WAG process through a pseudo-miscible formulation by means of coupling a full-physics reservoir simulator with commercial optimization and uncertainty software. The results are analyzed and presented in a comparative manner by means of tornado charts showing the significance of each decision and uncertainty variable.
Using Polymer Alternating Gas to Maximize CO2 Flooding Performance
Authors: Li W. , Schechter D. S. 
Published: February 2021

Abstract
Carbon dioxide (CO2) has been used commercially to recover oil from reservoirs by enhanced oil recovery (EOR) technologies for over 40 years. Currently, CO2 flooding is the second most applied EOR processes in the world behind steamflooding. Water alternating gas (WAG) injection has been a popular method to control mobility and improve volumetric sweep efficiency for CO2 flooding. The average improved recovery is about 9.7%, with a range of 6 to 20% for miscible WAG injection. Despite all the success of WAG injection, sweep efficiency during CO2 flooding is typically a challenge to reach higher oil recovery and better apply the technology.
This paper proposes a new combination method called polymer alternating gas (PAG) to improve the volumetric sweep efficiency of the WAG process. The feature of this new method is that polymers are added to water during the WAG process to improve mobility ratio. In the PAG process, polymer flooding and immiscible/miscible CO2 injection are combined.
To analyze the feasibility of PAG, models considering both miscible and polymer flooding processes are built to study the performance of PAG. In this paper, the sensitivity of polymer adsorption and concentration are studied. The feasibility of PAG in reservoirs with different permeabilities, different Dykstra-Parsons permeability variation coefficients (VDPs), and different fluids are also studied. A reservoir model from a typical section of the North Burbank Unit (NBU) is used to compare the performance between PAG, WAG, and polymer flooding. This study demonstrates that PAG can significantly improve recovery for immiscible/miscible flooding in homogeneous or heterogeneous reservoirs.
Can Indigenous Bacteria be Utilized for Increasing Oil Recovery from Trinidad Oil Reservoirs?
Authors: Rambaran N. , Maharaj S. , Hosein R. 
Published: February 2021

Abstract
In Microbial Enhanced Oil Recovery (MEOR) oil mobility and oil recovery is increased by growing and reproducing microbes (bacteria) in oil reservoirs. The oil reservoir is either innoculated with a proprietry bacteria and then fed to grow or indigeneous microbes present are fed by the injection of a suitable nutrient identified from labotatory experiments. The metabolic by-products produced by these microorganisms causes a reduction in oil viscosity and interfacial tension and an increase in oil mobility. Although MEOR is not popular, the open literature has shown this to be a low cost mechanism that can be implemented with waterflood projects to increase the recovery of residual oil by another 1-5 %.
In this study an oil sample from an oil reservoir in the South of Trinidad was selected and the indigenous bacteria present was identified to be mainly of the Bacillus species. A quantification of this indigenous bacteria by plate counts showed that the aerobic colony forming units (CFU) was about 1.5×106 CFU/ml whereas the observed anaerobic plate counts was about 9.0×102 CFU/ml. Growth of the indigenous bacteria was stimulated by innoculating the oil sample with five different nutrient formulations for a period of three weeks so as to select the most suitable nutrient. However, the growth in bacteria was too numerous to count even after one week.
Experimental measurements showed that the sample innoculated with the nutrient broth formulation had the greatest change in oil properties. The reduction in oil viscosity was 49 % and the reduction in interficial tension was 17 %. The results from this study can be included in waterfloood simulation studies for suitable oil reservoirs in Trinidad to determine the added increase in oil mobility and oil recovery from a combination of waterflood and MEOR.
Numerical Simulation of Shale Gas Development Based on Complex Fracture Network Growth
Authors: Ye D. , Yin C. , Li Y. , Wang S. , Qin G. , Chen H. 
Published: February 2021

Abstract
Micro-seismic result has shown that compared to conventional reservoir, more complex fracture network will be generated in shale gas reservoirs after hydraulic fracturing stimulations, which provides key channels for shale gas to flow in economic rate. It is vitally important to recognize complex fracture network and model such complex system to better understand gas develop process, optimize hydraulic fracturing design, and determine development plans of shale gas reservoirs.
Our proposed model enable realistic modeling of complex fracture network growth even with some uncertainty (SPE 157411), but it is possible to represent large-scale fracture network distribution in reservoir modeling and numerical simulation of shale gas development. In this paper, we used this proposed model to generate hydraulic fracture network distribution in shale formation, taking into account interaction between hydraulic fracture and actual large-scale natural fractures. Integrating hydraulic fracture network results and natural fractures in non-stimulated area, highly constrained unstructured gridding and a connection list are constructed, using the Discrete Fracturing Modeling (DFM) method. This model can effectively predict production performance. With real-world well data, the simulation system calibration is done, and the simulated well production performance has good agreement with real-world producing data. Using this simulation system, effective stimulated reservoir volume (ESRV) is also predicted.
The proposed approach is capable of modeling complex fracture network propagation and predicting well producing rate, if information data on multi-scale pre-existing natural fracture is available. This approach provide one opportunity to predict well production performance and effective stimulated reservoir volume (ESRV), which is also significant for shale gas development plan.