bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimization of Liquid-Assisted Gas Lift Processes for Production Enhancement by Using Transient Computer Simulations
Authors: Thiberville Caitlyn , Wang Yanfang , Kam Seung Ihl 
Published: October 2020

Abstract
Reservoir pressure depletion and liquid loading depress production in mid-to late-life producing wells. While pressure depletion can be difficult to combat and requires large scale solutions, liquid-loaded production tubing is easily remedied by on-site, individualized artificial lift solutions, such as sucker rod pumping, plunger lift, or gas lift, to name a few. A recent experimental study of Coutinho et al. (2017), using 2,788 ft depth vertical well with 2.88-inch ID tubing and 4.89-inch ID casing, shows that liquid-assisted gas lift (LAGL) processes can overcome difficulties in conventional gas lift, one of the most popular artificial lift methods in both onshore and offshore environments, and aid in cost reduction for operations by decreasing the onsite energy and infrastructure needs to unload a well.
Following the outcome of the experimental study, this study investigates how to further refine LAGL operations by conducting transient computer simulations using OLGA. The first step is to match the experimental data (i.e., history of bottomhole pressure and injection pressure) to extract model parameters for the simulations to follow, the second step is to perform 119 different simulation runs as well as analysis of resulting pressure and liquid-holdup histories in a wide range of gas and liquid flowrates, and the last step is to show how to implement the optimization technique by using the contour maps of variables and parameters of interest to optimize.
The results show that the two contour maps of required maximum injection pressure and liquid holdup in the tubing, as a function of gas and liquid flowrates, can serve as a useful means of seeking the optimum operating conditions. In addition, it is also shown that there are multiple sets of two contour maps, equivalently, to be employed for a similar analysis depending on various field scenarios or constraints (such as compressor capacity, limited gas supply, and separator capacity). Pressure loss and phase fraction, through complicated multiphase flow physics and flow regimes, play a key role behind the presence of optimum operating conditions during liquid unloading process.
Effect of Silica Nanoparticles on the Oil Recovery During Alternating Injection with Low Salinity Water and Surfactant into Carbonate Reservoirs
Authors: Olayiwola Saheed Olawale , Dejam Morteza 
Published: October 2020

Abstract
Application of nanoparticles (NPs) for enhanced oil recovery (EOR) has gained a lot of attention in recent years. Several laboratory studies have shown that the injection of nanofluid leads to a significant amount of oil recovery by modifying the fluid and rock/fluid properties, including the viscosity, interfacial tension (IFT), and wettability. Although the potential of NPs to improve oil recovery is magnificent, the effect of NPs during alternating injection is still vague. The main objective of this study is to investigate the best recovery mechanisms during alternating injection of NPs, low salinity water (LSW), and surfactant and transform the results into field-scale technology.
The results of the laboratory coreflooding experiments, which are performed on different core plugs taken from Indiana limestone (carbonate) reservoir, are presented in this study. To determine the best recovery mechanisms, different combinations of alternating injection of silica NPs, LSW, and Sodium Dodecyl Sulfate (SDS) surfactant into the selected cores are conducted at temperature and pressure of 70 °C and 3,000 psi, respectively. The experimental procedure is designed to reflect the best industrial practice for the injection of fluids into the reservoir. This study also investigates the effect of silica NPs on the IFT and the wettability at aforementioned conditions.
The outcome of these experiments revealed that the tertiary injection of NPs results in additional oil recovery beyond the limit of LSW. An additional oil recovery of 5-6% is achieved by alternating injection of NPs and surfactant after injection of LSW. Therefore, a total oil recovery of 8-11% is obtained from alternating injection of LSW, NPs, and surfactant. However, it was observed that less than 5% of the oil in place is recovered from the tertiary alternating injection of NPs dispersed in LSW and surfactant. The difference in the results is attributed to the wettability alteration by the NPs beyond the limit of the LSW and the reduction in the IFT with/without surfactant. The interpretation of the results of this study improves the understanding of the key mechanisms and the best recovery mechanisms for the application of NPs for EOR in carbonate reservoirs.
Multi-Phase Rate Transient Analysis Considering Complex Fracture Networks
Authors: He Youwei , Tang Yong , Qin Jiazheng , Yu Wei , Wang Yong , Sepehrnoori Kamy 
Published: October 2020

Abstract
Application of horizontal wells and hydraulic fracturing achieves commercial productivity of unconventional oil and gas resources. Complex fracture networks (CFN) provide flow channels and significantly affect well performance in unconventional reservoirs. However, traditional rate transient analysis (RTA) models barely consider the effect of CFN on production performance. Besides, the impact of multi-phase flow on rate transient behaviors is still unclear. Neglecting these crucial effects could cause incorrect rate transient response and erroneous estimation of well and fracture parameters.
To fill this gap, this paper investigates the multi-phase rate transient behaviors considering CFN, and tries to investigate in what situations the multi-phase model should be used to obtain more accurate results. Firstly, an embedded discrete fracture model (EDFM) is generated instead of local grid refinement (LGR) method to overcome the time-intensive computation performance. The model is then coupled with reservoir models using non-neighboring connections (NNCs). Secondly, eight cases are designed using the EDFM technology to analyze the effect of natural fractures, formation permeability, and relative permeability on rate transient behaviors. Thirdly, Blasingame plot, log-log plot, and linear flow plot are used to analyze the differences of rate transient response between single-phase and multi-phase flow in reservoirs with CFN. For multi-phase flow, severe deviations can be observed on RTA diagnostic plots compared with single-phase model. The combination of three kinds of RTA type curves can obviously characterize the differences from early to late flow regimes and improve the interpretation accuracy as well as reduce the non-unicity. Finally, field application in Permian Basin demonstrates that multi-phase RTA model and type curves are required for analyzing the production and pressure data since single-phase RTA analysis will lead to big errors for interpretation results.
Completion Effects on Diagnosing Multistage Fracture Treatments with Distributed Temperature Sensing
Authors: Sakaida Shohei , Zhu Ding , Hill A. D. 
Published: October 2020

Abstract
Distributed temperature sensing (DTS) is a valuable tool to diagnose multistage hydraulic fracture treatments. When a stage interval is shut-in, the clusters which take more fluid during pumping warm up more slowly. Therefore, the fluid volume injected into each cluster can be quantitatively interpreted by numerical inversion of the warm-back temperature behavior. This general concept assumes that the different warm-back behavior is controlled by only the injected fluid volume, however, recent observations of DTS data indicate that completion configurations significantly influence the warm-back behavior.
This paper investigates the completion effects on the DTS interpretation. In ideal conditions, when a stage is fractured, the upstream stage intervals should show an almost uniform temperature that is close to the injected fluid temperature. This is due to the high fluid velocity of injected fluid in the wellbore, and the upstream intervals have not been perforated (non-communicating intervals). Thus, the only heat transfer is heat conduction between the wellbore fluid and the surrounding reservoir. But the field DTS data show considerably irregular variations in temperature along the upstream stage intervals. These variations are caused by the completion effects. The non-uniform temperature profile is caused by different heat transfer behavior induced by completion hardware along the production casing string such as joints, clamps, and blast protectors, and by the sensing cable location in the cement, as well as the cement quality. Since the heat transfer behavior impacts the warm-back behavior as well as the temperature profile, the completion effects need to be considered in DTS interpretation.
A method of DTS interpretation considering the completion effects to diagnose multistage fracture treatments was developed. Since the heat transfer between a wellbore and a reservoir depends on the overall heat transfer coefficient describing heat conduction through the completion in a forward model, this parameter needs to be tuned along the entire wellbore. To calibrate the completion effect, the temperature inversion is conducted using the temperature measured at a stage interval that is upstream of a stage interval currently being treated. Since the interpreted stage interval is not perforated at that time, the thermal behavior at the non-communicating interval is governed by only the heat conduction through the completion environment. Once the effective values of the overall heat transfer coefficient are estimated along the interpreted stage interval, they can be assumed to be constant physical parameters. Then, the fluid volume distribution is interpreted by using the effective overall heat transfer coefficient profile along each interval.
The interpretation method developed in this study was demonstrated using field data, and it was concluded that the new DTS interpretation method provides more accurate diagnosis of fracture treatments.
Novel Completion Design to Bypass Damage and Increase Reservoir Contact: A Middle Magdalena, Central Colombian Case History
Authors: Polo Rosana , Arciniegas Jaime , Valencia Brian , Vulgamore Travis , Nuñez Walter , Ortega Camilo , Palisch Terry , Velez Eduardo , Tineo Roberto 
Published: October 2020

Abstract
The La Cira Infantas field is located in the Middle Magdalena basin in the Santander region of central Colombia. This oil-producing development is under secondary waterflood using five-spot and inverted seven-spot patterns. The reservoir has high vertical and horizontal heterogeneity, and there was concern about effectively draining the reservoir. A new hydraulic fracturing design was deployed for the first time in Colombia (and South America) to improve drainage and surveillance.
With over 1200 producers and 500 injectors, the La Cira Infantas waterflood is well established. Waterflood surveillance indicated less-than-optimal recovery due to near-wellbore skin in the injectors and suspected poor height coverage. A novel proppant technology was incorporated into the fracture design allowing for consolidation of the proppant pack in the fracture with low bottomhole temperature and minimal stress on proppant, enabling long-term undamaged injectivity. This technology also incorporates an inert tracer into the proppant grains, which provides propped height determination after the treatment using a neutron log. This multi-faceted proppant technology was successfully deployed on one well, and additional wells are planned in 2020.
This paper will first review the background of the field development including current completion techniques, along with the challenges being faced with the waterflood recovery. It will review the self-consolidating proppant technology and show the benefits of its use in this application to promote high-conductivity fractures and minimize damage to injectivity. The companion tracer technology will be presented along with plans to perform neutron logging and identify propped fracture height. This information can be fed into fracture propagation models to determine the fracture geometry, which is then used for reservoir and waterflood surveillance analysis. The technique allows for meeting the goal to improve injectivity into both high-skin and low-permeability reservoirs.
Although this proppant technology has been used in other frac pack applications, this is one of the first case histories of the technology being used on land for improving injectivity and waterflood coverage in Colombia. This paper will be useful for reservoir and completion engineers working on waterflood fields that contain vertically and horizontally heterogeneous formations, and wish to maintain undamaged injectivity, improve waterflood sweep efficiency, and monitor the proppant pack over time.
A New Horizon in Corrosion Prevention Using State of the Art High Power Laser Cladding Technology
Authors: Assiri Wisam , Asiri Ahmed , San Roman-Alerigi Damian , Batarseh Sameeh , Salman Muntadar 
Published: October 2020

Abstract
The objective of this work is to present a successful case study of deploying high power laser cladding in highly sour wells as protection from corrosion. High power laser cladding uses superalloy material and is welded to the pipe, creating a thin and strong film that adheres to the steel pipe. The technology is cost-effective and provides a long-term solution, extending the life of the pipes, casing, tubing, and other parts.
The method requires preconditioning the completion at the surface, applying a thin layer of superalloy (1 mm), and bonding it to the base material with a laser. The process will create a chemical bond between steel and the superalloy, which will result in a resistive layer facing the corrosive fluids. The technology was applied to carbon steel coupons (T-95 grade) and was cladded with three different superalloys Inconel-625, Inconel-825, and Hastelloy C-276. A bare coupon was used as a reference. The coupons were kept for three months downhole and later retrieved for analysis.
The technology was tested in extremely sour wells for three consecutive months. Well-A produces a high concentration of hydrogen sulfide (H2S) (35,000 ppm) while Well-B has a concentration of 14,000 ppm. A detailed analysis, including composition, X-ray fluorescence, environmental scanning electron microscope, and surface profiling on the coupons showed that the cladded samples have excellent resistance and no traces of corrosion on all the cladded coupons.
High power laser cladding is a cost-effective and promising technology that can extend the life of wells and minimize the frequency to replace the tubing due to corrosion issues. The cladded sample exhibits a more durable structure than the substrate materials. The superalloy thin layer protects from corrosion as it is a new pipe.
Using Markers for Production Logging in Horizontal Gas Wells with Multistage Hydraulic Fracturing
Authors: Katashov Alexander , Ovchinnikov Kirill , Belova Anna , Husein Nadir , Rivas Oscar , Buyanov Anton , Suprankov Kirill 
Published: October 2020

Summary
The need for the use of modern technologies for diagnosing the work of the developed facilities and clarifying information on the productivity of the target formation arises when making decisions on the control of development, including designing and planning various kinds of technological measures, as well as conducting research to monitor the current state of existing wells. Traditional methods for monitoring the inflow profile are not always effective and cost-effective, especially when it comes to hard-to-recover reserves. One of the most progressive solutions is the use of marker studies based on the selection of markers from the produced fluid and their subsequent identification in samples taken at the wellhead [1]. The main advantage of this technology is that there is no need to suspend work for hoisting operations in order to obtain informative field-geophysical data during well operation. Moreover, the undoubted advantage of marker monitoring is its long-term nature since the technology allows continuous downhole data obtaining within several years. The subject of this work is a gas well with an extended horizontal wellbore, in which the 18-stage hydraulic fracturing using marked quartz polymer-coated sand was carried out.
A Petrophysical Method to Estimate Production Rate vs. Time Performance, and to Define Drainage Areas and Recovery Efficiencies
Authors: Holmes Michael , Holmes Antony , Holmes Dominic , Swartz Kent , Jones Brian , Aye Naing , Zimbrick Grant 
Published: October 2020

Abstract

Objective/Scope
The main objective is to build on prior publications of decline curve analysis, based on theoretical producing and fluid flow characteristics (Matthews and Lefkowits 1956, Fetkovitch 1975, Cox 1948).
In this paper, we relate petrophysical predictions of ultimate oil recovery to actual rate-time well performance by adjusting recovery efficiencies and well-bore drainage areas.

Method/Procedure/Scope
From an analysis of a number of producing wells in the Permian Basin a model (Zimbrick) has been derived for average decline curve performance. This model has been found to work in other basins; however, basin specific models are likely to be required in some situations.
This model is then combined with petrophysical estimates of recovery efficiencies to generate rate vs. time decline curves. This is then compared with actual production to determine drainage area. Three basic questions are then addressed:
Additional adjustments might then be necessary. Results can be interpreted as follows:

Results/Objectives/Conclusions
Results from the analyses of four oil wells in the Big Horn Basin of Wyoming are presented. All four wells have excellent log suites allowing for reliable petrophysical analysis, are now depleted, and have rate-time data available.
The nominal well spacing is for 15-acre drainage. Petrophysical predictions for rate-time performance were run for two basic cases:
Using a constant recovery efficiency of 20% the drainage areas were adjusted to get an exact match with actual performance.
For three of the four wells, adjusted drainage areas are significantly greater than 15 acres.
Factors influencing the calculated drainage areas are:

Novel/Additive Information
The method compares petrophysical estimates of recoverable hydrocarbons with actual rate-time performance, allowing for considerations of drainage areas and recovery efficiencies and the possibility of production coming from a fracture system and/or adjacent unperforated intervals.
Estimates can be made from the petrophysical analysis of adjacent undrilled locations of rate-time performance before the well is completed.
Dynamic Torque and Drag Model
Authors: Samuel Robello , Huang Wenjun 
Published: October 2020

Abstract
It is generally acceptable to use soft string model for simple wells and stiff string for high dogleg wells. But these models fail to reveal the complex mechanical behaviors of tubular string in tripping in, tripping out, and sliding drilling operations with time as some segments of tubular string may move upward and downward alternatively. As a result, the model under predicts or over predicts the behaviors of tubular string, and requires multiple calibrations of friction factor. To avoid this, a new model has been developed to estimate dynamic torque and drag. In the new model, the effects of tubular vibration, drill fluid, viscous force, and velocity-dependent friction force are all considered, which overcomes the shortcomings of all previous models. The new model can be used for calculating dynamic mechanical behaviors of tubular string under tripping in, tripping out, and sliding drilling operations. The results provide new insights that have not been previously presented and will provide valuable insights into well planning and designing.
Prediction of Zonal Flow Allocation Using Fiber-Optics Monitoring In a Complex Injector Well System
Authors: Satti Rajani , Bale Derek , Patel Amar , Nazarenko Pavel , Avella Oscar , Solorzano Pedro , Sanchez Walter , Giosa Carlos , Satizabal Monica , Vega Sandra , Hernandez Nini , Coronel Ivan 
Published: October 2020

Abstract
Injector well completions are typically carried out using two methods: simple and selective. The performance of injector wells has traditionally been evaluated using spinner-based injection logging tools (ILTs) or on-demand fiber optic distributed temperature and acoustic (DTS or DAS) sensing while logging the well performance every 3 months or once a year depending on the application. However, with such methods utilizing a snap shot approach, critical well performance information or possible anomalies are often missed due to measurements taken only during certain periods. Therefore, operators have explored the use of advanced fiber-optics methods such as permanent distributed temperature sensing (DTS) and permanent distributed acoustic sensing (DAS), that provide continuous, real-time measurements to enable understanding of dynamic well behavior at all times and mitigate any deferred or behavioral problems.
Of relevance to this work is a vertical, injector well in a competent sandstone formation of the Heavy Oil Chichimene field in Llanos Basin, Colombia. As a first step of the fiber-optics monitoring strategy, a careful evaluation of DTS and DAS based fiber-optics methods was conducted. Based on the data analysis and operational history, DAS-based fiber optics monitoring was chosen as the most effective monitoring solution for this well. Subsequently, a proprietary DAS algorithm was developed to analyze the data and estimate the flow allocation for all the four zones. The results include waterfall acoustic energy maps, temporal flow allocation profiles and most importantly, the zonal flow allocation values.
Predicted (DAS) zonal flow allocation data was compared with traditional injection logs (ILT) under different operational conditions (varied injection flow rates and valve choke settings). Based on comparable agreement between DAS and ILT data, the operator decided to replace ILT runs with DAS-based fiber optic monitoring, resulting in lower operational costs while enabling near real-time monitoring, and providing the continuous distributed data essential for the dynamic monitoring of the well. The successful application of fiber-optics monitoring to provide an injection profile in conjunction with a surface-controlled electric valve system demonstrates a significant potential to optimize the injection process in complex injector wells. Further, remotely controlling, monitoring and optimizing injection rates into the multi-segmented zones improves the service life of the injection operations, eliminates future intervention costs, and increases ultimate recovery.