bluuebunny/crossref_metadata_2025_split huggingface dataset:
Reviving a Mature Field in Ecuador by Rethinking Energy Sustainability and Reservoir Management
Authors: Astudillo Ricardo , Orellana Ney , Lozada Santiago , Añazco Jorge , Bailón Luis , Espín Jorge , Freire Juan , Gaibor Andrés , Martínez Edsson , Muñoz Edwin , Padilla Carlos , Román Servio , Tamayo Telmo , Villegas Santiago 
Published: July 2020

Abstract
This paper summarizes the strategies implemented in a mature oil field in Ecuador to revive its production by improving energy efficiency, increasing fluid production and incorporating proved reserves. Results are shown in terms of the field energy efficiency index, energy consumption on ESPs, oil production, annual production decrease tendency and reserves incorporation.
The Choke Model philosophy was implemented as a strategy for field development optimization. This methodology allowed the operator to identify that the main chokes were the production wells and the power. By using divergent and convergent thinking techniques focused on these chokes, four main strategies were selected: reduce the pipe diameter size of a fluid line, artificial lift system energy assessment, reactivate closed wells and recomplete others. Complete description of the methodology is provided in detail to permit readers to analyze this successful case.
The reduction of pipe size diameter of a fluid line increased the mobility of the fluid from the well pads to the plant, eliminated the recirculation of water and thus increase the energy efficiency indicator of fluid handling from 9,770 to 10,190 BFPD/HP. The energy assessment of the artificial lift systems identified the inefficient wells that were scheduled for ESP redesign and technology upgrade with an energy improvement of 30%. All these energy efficiency improvements lead to rise fluid production.
Based on the possibility to increase fluid production, wells reactivations, ESP upsizing’s and recompletions were planned. The team used a screening process to optimize candidates, gaining 2,010 BOPD, in average, over the baseline production profile since September 2017 to December 2018.
The activities performed and well interventions diminished the annual oil production decline rate from 14% to 8%, allowed the operator to incorporate 4.8 MBBLS of proved reserves in 2018 and generate 7.6 MUSD of free cash flow in the same year.
All the strategies were successfully achieved, and they accomplished the objectives of reviving a mature field, extending its life and generating value for the operator. None of the previous were possible without rethinking energy sustainability and reservoir management.
The novelty of this work is the multidisciplinary approach and innovation methodology implemented to provide solutions to operational field chokes by identifying feasible projects in terms of technique, time and economics.
A Thorough Review and Latest Advances in Shale Reservoirs: Seismic to Surveillance
Authors: Temizel Cenk , Canbaz Celal Hakan , Gok Ihsan Murat , Roshankhah Shahrzad , Palabiyik Yildiray , Deniz-Paker Melek , Hosgor Fatma Bahar , Ozyurtkan Hakan , Aksahan Firat , Gormez Ender , Kaya Suleyman , Kaya Onur Alp 
Published: July 2020

Abstract
As major oil and gas companies have been investing in shale oil and gas resources, even though has been part of the oil and gas industry for long time, shale oil and gas has gained its popularity back with increasing oil prices. Oil and gas industry has adapted to the low-cost operations and has started investing in and utilizing the shale oil sources significantly. In this perspective, this study investigates and outlines the latest advances, technologies, potential of shale oil and gas reservoirs as a significant source of energy in the current supply and demand dynamics of oil and gas resources.
A comprehensive literature review focusing on the recent developments and findings in the shale oil and gas resources along with the availability and locations are outlined and discussed under the current dynamics of the oil and gas market and resources. Literature review includes a broad spectrum that spans from technical petroleum literature with very comprehensive research using SCOPUS database to other renowned resources including journals and other publications. All gathered information and data are summarized. Not only the facts and information are outlined for the individual type of energy resource but also the relationship between shale oil/gas and other unconventional resources are discussed from a perspective of their roles either as a competing or a complementary source in the industry. In this sense, this study goes beyond only providing raw data or facts about the energy resources but also a thorough publication that provides the oil and gas industry professional with a clear image of the past, present and the expected near future of the shale oil/gas as it stands with respect to other energy resources.
Among the few existing studies that shed light on the current status of the oil and gas industry facing the rise of the shale oil are up-to-date and the existing studies within SPE domain focus on facts only lacking the interrelationship between heavy and light oil as a complementary and a competitor but harder-to-recover form of hydrocarbon energy within the era of rise of renewables and other unconventionals. This study closes the gap and serves as an up-to-date reference for industry professionals.
Limited Access Ranging Solution – Mitigation of Significant Anti-Collision Issues
Authors: Hinke Sean , Hooff Gerritt 
Published: July 2020

Abstract
This paper explores four unique case studies where a novel limited-access ranging system was used in real world examples of well placement with close-proximity drilling applications. The case studies highlight enhanced recovery and reduced complexity for the overall well construction process. The method uses a gradient ranging system along with surface excitation to create an active magnetic field along the target wellbore to acquire a distance and direction measurement. This arrangement eliminates the need for the typical access-dependent ranging conveyance using coiled tubing or wireline systems. With this approach, several logistical and technical constraints are removed, making several unique solutions possible, such as ranging to abandoned wells and to wells with casing damage or other obstructions, and as well as high-temperature applications as no intervention is required to the target wellbore.
The first case study used magnetic ranging to an abandoned wellbore in an approach similar to drilling a standard Steam Assisted Gravity Drainage (SAGD) injector well. The second study highlights an anti-collision scenario which required toe-to-heel ranging to an abandoned wellbore. The third used magnetic ranging as an anti-collision tool performing toe-to-heel ranging to a currently producing wellbore where completion tools were left in the hole. The fourth scenario used the technology to drill a parallel well where a casing and tubing obstruction limited the ability to run traditional ranging equipment.
Through this paper, the authors will illustrate the benefits of this technology in their use in Steam Assisted Gravity Drainage drilling applications and expand on potential benefits of this technology in other close-proximity drilling applications for either paralleling or anti-collision purposes.
Development Strategies in the Sureste Salina Del Istmo Basin: Sustainable Production Replacement Options
Authors: Zarea Maziar , Mohamed Kareemah 
Published: July 2020

Abstract
With the advent of the Mexican Energy Reform, foreign companies have flocked to the southern Gulf of Mexico (GoM) attempting to replicate the same level of commercial success as seen in the U.S. GoM. There have been recent notable discoveries as well as significant untapped potential in existing discoveries (approximately 12 Bboe 2P remaining recoverable reserves), largely in the shallow waters of the infrastructure-rich, re-emerging Sureste basin. These fields present a near-term path to production to stem Mexico's production decline. In the Sureste Basin, 54% of offshore fields have field sizes of less than 100 MMboe 2P recoverable reserves and are in the discovery/appraising phase. We have developed a screening method which ranks field candidates for near term development to add much needed oil production.
Additionally, for these top ranked fields, through leveraging a combination of the following factors can result in 3.4 Bboe of 2P recoverable reserves monetized within 3-4 years with an overall cost reduction.
The concept of "Hub and spoke" field development can be used to approach to utilize existing platform capacity and tie in marginal fields. Utilizing modular and standardized platform configurations which can result in a compression of development cycle times by using "off the shelf" designs. By reducing non-productive rig days, there can be a overall need for less rig mobilization. Digitalization enabled potential change in the operating model, facing a potential 60% reduction in offshore staffing due to relocation of maintenance crews onshore.
To achieve this cost reduction target identification of field candidates is vital. This screening methodology employs a cross functional approach to optimizing subsurface reserves while incorporating above-ground risk, linking existing infrastructure capacity and new technology deployment. This methodology was applied to 30 discoveries in the Sureste basin which have never been produced and modeled 3 cases evaluated on time to first production and cost reduction. This can contribute to the enhancement of Mexico's energy sector and present acquisition targets to operators and infrastructure owners. These concepts may be applied to other analogous asset types.
A Two-Phase Non-Linear One-Dimensional Flow Model for Reserves Estimation in Tight Oil and Gas Condensate Reservoirs Using Scaling Principles
Authors: Ruiz Maraggi Leopoldo M. , Lake Larry W. , Walsh Mark P. 
Published: July 2020

Abstract
A common approach to forecast production from unconventional reservoirs is to extrapolate single-phase flow solutions. This approach ignores the effects of multi-phase flow, which exist once the reservoir pressure falls below the bubble/dew point. This work introduces a new two-phase (oil and gas) flow solution suitable to extrapolating oil and gas production using scaling principles. Additionally, this study compares the application of the two-phase and the single-phase solutions to estimates of production from tight oil wells in the Wolfcamp Formation of West Texas.
First, we combine the oil and the gas flow equations into a single two-phase flow equation. Second, we introduce a two-phase pseudo-pressure to help linearize the pressure diffusivity equation. Third, we cast the two-phase diffusion equation into a dimensionless form using inspectional analysis. The output of the model is a predicted dimensionless flow rate that can be easily scaled using two parameters: a hydrocarbon pore volume and a characteristic time. This study validates the solution against results of a commercial simulator. We also compare the results of both the two-phase and the single-phase solutions to forecast wells.
The results of this research are the following. First, we show that single-phase flow solutions will consistently underestimate the oil ultimate recovery factors for solution gas drives. The degree of underestimation will depend on the reservoir and flowing conditions as well as the fluid properties. Second, this work presents a sensitivity analysis of the PVT properties that shows that lighter oils (more volatile) will yield larger recovery factors for the same drawdown conditions. Third, we compare the estimated ultimate recovery (EUR) predictions for two- and single-phase solutions under boundary-influenced flow conditions. The results show that single-phase flow solutions will underestimate the ultimate cumulative oil production of wells since they do not account for liberation of dissolved gas and its subsequent expansion (pressure support) as the reservoir pressure falls below the bubble point. Finally, the application of the two-phase model provides a better fit when compared with the single-phase solution.
The present model requires very little computation time to forecast production since it only uses two fitting parameters. It provides more realistic estimates of ultimate recovery factors and EUR, when compared with single-phase flow solutions, since it considers the expansion of the oil and gas phases for saturated flow. Finally, the solution is flexible and can be applied to forecast both tight oil and gas condensate wells.
Unified Oil and Water Fractional-Flow Functions: Improving Waterflood Performance Analytical Modeling Techniques
Authors: Tillero Edwin , Mogollon José Luis 
Published: July 2020

Abstract
Applying simpler and more powerful waterflood performance analytical modeling tools to history match and forecast fluid (oil and water) production rates is always a subject of interest. Increasing improvements of these no grid-based tools trigger their use as predictive and trustworthy precursors of grid-based modeling, providing significant insights and allowing a previous assessment of historical and future waterflood performance without a significant time- and investment-consuming modeling.
Setting up a unified fractional-flow model (UFFM), that considers both the traditional Buckley-Leverett-based stable fractional-flow model (BLBFFM) and instabilities due to oil viscous-fingering effect, to accurately predict the oil recovery from traditional waterflood performance analytical modeling tools is the objective of this paper. The unification is based on using appropriate kro/krw vs. water saturation expression that considers viscous-oil effect based on the effective finger model (EFM), allowing the substitution of a classic semilog linear relationship of kro/krw vs. Sw (constant coefficients A and B) by a unified nonlinear oil-water relative permeability ratio.
This UFFM approach aims to boost the analysis from well-known waterflood performance analytical methods: water-oil ratio (WOR), X-plot, Y-function and the capacitance-resistance model (CRM). Such waterflood performance diagnosis methods, traditionally based on the BLBFFM, were redefined by using the new UFFM. Conceptual and field cases were tested using new definitions to evaluate impact on ultimate oil recovery and various reservoir parameters.
Results demonstrated that unified approach improves reliability when estimating oil recovery for stable and unstable waterfloods. As expected, they quantitatively yield, for example, that the greater the viscous-fingering effect, the lower the viscous-oil recovery.
The universalization of fractional-flow functions (fw and fo) by incorporating UFFM upon all traditional waterflood performance methods based on BLBFFM can allow insights of important physical phenomenon that affect relative permeability, such as the oil-water viscosity ratio, injection rate, and known physical parameters affecting ultimate oil recovery.
Sand Control Optimization for Rubiales Field: Trade-Off Between Sand Control, Flow Performance and Mechanical Integrity
Authors: Mayorga Cespedes Edgar Alberto , Roostaei Morteza , Uzcátegui Alberto A. , Soroush Mohammad , Izadi Hossein , Hosseini Seyed Abolhassan , Schroeder Brad , Mahmoudi Mahdi , Gomez Dionis M. , Mora Edgar , Alpire Javier , Torres Joselvis , Fattahpour Vahidoddin 
Published: July 2020

Abstract
Designing/Selecting the proper sand control mechanism for horizontal wells in unconsolidated heavy-oil reservoirs tend to be under-looked in some cases. Stand-alone completions pose some sand control challenges, which could jeopardize the oil production or even lead to critical problems. Massive sand production, screen/formation plugging, formation of velocity hot-spots and mechanical integrity failures are some of the well-known issues. This study attempts to optimize the sand control design for horizontal wells in a heavy-oil field in Colombia.
A careful selection of representative core data was made to study the variation of sand Particle Size Distribution (PSD) within the development area. Reservoir fluid properties were analyzed. Based on PSD variation and current design criteria in the industry, several seamed slotted-liner configurations were proposed as an alternative completion for testing. Later, a series of large-scale Sand Retention Tests (SRTs) were performed to assess the selected alternatives under typical field production conditions. Effects of aperture size and open to flow area (OFA) were investigated to evaluate flow and sand control performance.
This investigation started by a detailed study of the PSD, particle shape variation and composition of fines in the development area. The PSDs were then classified into four distinct minor and major sand facies, ranging from medium to very coarse sand with different fines content. Further investigations have shown that current design is only suitable for a limited number of PSDs, while the overall PSD classes indicate requirement of wider slot aperture sizes. The results of the SRTs indicated that the flow performance of the screen is mainly controlled by the slot aperture. Choosing the optimized aperture size avoids unacceptable sanding even for the multiphase flow scenarios with gas. Results also indicated that by increasing the aperture size and application of the seamed slots for the studied formation, plugging could be mitigated. Finally, a detailed Finite Element Analysis (FEA) was conducted to compare the mechanical integrity of the current slotted liner design and the optimized design obtained from the experimental testing.
A comprehensive sand control design workflow for cold primary heavy oil production in horizontal wells is presented in this work. The current study is one of the first that investigates and compares conventional straight slotted liners with seamed slotted liners at larger scale for a field. Moreover, this study helps to better understand the effect of design parameters of seamed slotted liners on sand control, flow performance and mechanical strength.
Effect of Oil Production on the Price of Oil
Authors: Aguilera Roberto F. , Aguilera Roberto 
Published: July 2020

Abstract
The objective of this paper is to investigate the effect of oil production on the price of oil considering particularly the case of unconventional (tight and shale) reservoirs.
Five years ago, at LACPEC 2014 in Maracaibo, Venezuela, we presented an original paper and a methodology to investigate the price of oil. We stated in that paper that "with the vast global oil resource base and significant technological advances being implemented by the industry, oil prices could decrease in the future" (Aguilera and Aguilera, 2014). Given the good comparison between our 2014 LACPEC study and the actual oil pricing during the last 5 years, we use the same methodology for investigating possible ranges of oil prices in the future.
Our results stem from a successful match, using a Variable Shape Distribution (VSD) model, of the small and large variations of oil prices since 1861. Results are good, with a coefficient of determination (R2) larger than 0.98. We also match successfully oil consumption rates from 1861 to 2019 using a Global Energy Market (GEM) Model. The combination of the VSD and GEM, and our investigation on availability of oil resources, lead to the conclusion that our 2014 statement at LACPEC in Maracaibo remains current: "with the vast global oil resource base and the significant technological advances being implemented by the industry, oil prices could decrease in the future". Our methodology further indicates that, barring an unforeseen global disruptive event, oil prices will remain depressed for the foreseeable future. This supports the findings of Aguilera and Radetzki (2015) who in their book, The Price of Oil, forecast oil prices between $40 and $60 by 2035. This contrasts with the work of authoritative energy forecasting agencies who project rising prices in the coming decades. Also, as opposed to some oil companies, particularly some of the European organizations, that see the peak oil demand coming soon enough, e.g. the mid-2020s, our research indicates that it is unlikely that oil demand will peak in the coming decades.
The uniqueness of our forecasting methods for the oil price and global oil consumption is that our methods have remained unchanged since their creation (Aguilera and Aguilera, 2007) and yet they continue to generate reasonable results. This contrasts with methods of other organizations and commentators that change their forecasts repeatedly.
Novel Analytical Approach for Polymer Injectivity Tests in Los Perales Field, Argentina
Authors: Cocco Mauro Daniel , Volzone Darío , Fuzul Eduardo , Katz Román , Perez Diego Gastón 
Published: July 2020

Abstract
Polymer admission studies at the objective reservoir layers are one of the first critical experimental tests prior to field injection. Pressure build-up in the injector well is measured during a short period of time and its projections are used to select maximum polymer injection flow-rate and pumps. Complementary, polymer stability must be monitored during the injectivity test to reduce viscosity fluctuations, and a flowback test will finally validate the whole process asserting absence of polymer degradation at reservoir conditions.
In Los Perales three wells were tested for HPAM polymer-flood. Near-wellbore pressure transient analysis is not accurately resolved by numerical simulators, so an analytical pressure build-up model considering polymer non-Newtonian rheology was developed to make projections adjusted to measured data. Polymer thermal variations and degradation mechanisms (mechanical and chemical) in surface facilities have been also studied (Katz Marquez, 2019). Then, a flowback test in one of the wells was performed to check for polymer degradation and validate the whole assay.
During the injectivity test, measurements and further estimations, derived from the ad-hoc analytical model, showed that the objective polymer doses and injection flow-rate will be admitted by the reservoir. On the other hand, chemical degrading processes rise as challenging problems to deal with. Oxygen combined with hydrogen sulfide was found to be the main responsible for chemical degradation. One of the steps in the process of solving this issue was to develop an equation which allows us to predict viscosity behavior considering these effects. Hence, several ways to reduce degradation were implemented. Finally, the flowback test in one well validated the assay showing that combined degradation (mechanical and chemical) did not reduce active polymer concentration in more than 25%. In order to make degradation-free viscosity measurements, an ad-hoc 3D-printed anaerobic chamber for the viscometer was developed and successfully implemented.
The present work serves as a guideline to perform injectivity test, estimate well pressure build-up, deal with chemical and mechanical degradation processes and validate the process through a flowback test a further data analysis.