bluuebunny/crossref_metadata_2025_split huggingface dataset:
Trends in Vaca Muerta Horizontal Wells Stimulation
Authors: Johanis P. E. , Triffiletti G. E. 
Published: May 2017

Abstract
Until the recent crude and gas price decrease in late 2015, development in the Vaca Muerta shale experienced profitable production through improved methods, efficiency, and economics control.
To combine public domain hydrocarbon production datasets with detailed proprietary drilling information, operators and service companies can use completion, logging, and well stimulation data. These data enable analysis of trends and improvements that occur during drilling, fracturing, and production of horizontal wells targeting both shale oil and gas in the Vaca Muerta and help provide economic, efficiency, and productivity improvements.
In recent years, more than 500 wells have been drilled in the Neuquén basin in the Vaca Muerta, the majority of which are located in the Loma Campana field. Other areas under development include El Orejano, La Amarga Chica, Aguada Pichana, Sierras Blancas, Cruz de Lorena, Bandurria, Aguada Federal, La Invernada, Bajo del Choique, and Puesto Silva Oeste. As of January 2016, Vaca Muerta monthly production of oil and gas was 6.7 million bbl and 13 million barrels of oil equivalent (BOE), respectively, representing 12 and 5% of total Neuquén basin production.
A database was created including 47 records of horizontal stimulated wells that target the Vaca Muerta. Each register includes information related to location [well name, latitude, longitude, ground level, total depth (TD)]; production (operator, first oil date, effective time on, monthly oil, gas and water production); drilling (casing, liner, shoes, cementing); completion (directional survey, stages, clusters, perforations, plugs); fracturing [pump time, pressure, instantaneous shut-in pressure (ISIP), fracture gradient, horsepower, fluid type, injection rate, fluid volume, proppant type, proppant mesh, proppant mass, injection rate]; and production (cumulatives, rates, decline rate, recovery estimates, flow regime).
Several correlations and crossplots between variables were developed and analyzed to identify trends and establish normal and anomalous behavior. The validity of using early production to estimate longer periods was confirmed, enabling creation of a complementary series of production data with modeled forecasts and estimated ultimate recoveries.
Production data were then standardized by stages, horizontal length, proppant sacks (100 lbm) pumped, and fluids injected; after this, the records were sorted by productivity to determine average standardized production and typical completion and stimulation.
Observing these values over time highlights trends toward longer wells with more stages and smaller sized proppant. Simultaneously, a recent shift to shale gas objectives located slightly basinward is indicated by deeper wells, where less fluid and more horsepower were used during stimulation.
Field Treatment of an Injector Well in a Sandstone Formation Using a Low Corrosive Environmentally Friendly Fluid that Does Not Require Flow-Back
Authors: Nuñez W. , Bautista O. , Cepeda F. A. , Kleber M. A. , Dos Santos A. A. , Oliveira E. , Rodriguez O. 
Published: May 2017

Abstract
Throughout a waterflood project, injector wells can experience scale build up mostly related to formation-water incompatibilities; as a consequence, injectivity index (II) decreases and vertical conformance can suffer leading to poor sweep efficiency. Stimulation treatments are required to reestablish well injectivity; usually Hydrochloric acid and Regular Mud Acid are used in sandstone reservoirs. Such treatments involve a number of difficulties such as handling highly corrosive fluids, risk of clay instability, secondary reactions and time-consuming flowback of spent treatment in low pressure reservoirs.
Recently, a novel chemical was identified to effectively dissolve scale obstructions in injector wells while avoiding the operational constrains found in traditional acidizing jobs, including the need of flowback. Fluids containing the environmentally friendly chelating agent Glutamic acid N, N diacetic acid (GLDA), were tested in the laboratory under downhole conditions to evaluate the dissolution of a scale sample from the field composed by Fe2O3 and CaSO4. Additionally, core-flood, compatibility and corrosion tests were carried out to evaluate the interaction with clays, formation and well's metallurgy. Results showed effective dissolution of the scale sample, while being fully compatible with formation clays and fluids which indicated that the treatment could be left downhole and pushed into the formation without causing further formation damage. Furthermore, corrosion tests showed no need of corrosion inhibitor for a low carbon tubular under tested conditions.
Field implementation took place in an on-shore injector well completed selectively with injection valves between packers. A two stage treatment was designed; the target of the first phase was cleaning out the injection valve itself and the tubing-casing annular space of this interval, and the second stage aimed the dissolution of scale located in the perforations and deeper into the formation. Step rate tests were performed before and after the treatment to evaluate well injectivity. Low injection treatment rates and soaking allowed enough time for the GLDA to effectively dissolve the scale obstruction along the treated interval; spent treatment was pushed further into formation once regular water injection was reestablished with a 51% increase in its injectivity index. The use of GLDA in the field was considered cost-effective due to the lack of additives, no need for of N2 to kick-off flow-back, nor flow-back fluids neutralization and disposal.
Drilling Optimization of Argentina Horizontal Tight Sand Wells
Authors: Torres-Cabrera N. , Pozo M. , Finessi A. A. 
Published: May 2017

Abstract
Argentina tight sand wells present a hostile drilling environment with hard, abrasive, and interbedded lithology. Consequently, bottomhole assembly (BHA) behavior is difficult to predict; tools and drilling performance are often affected, leading to poor rates of penetration (ROP), unplanned trips to surface, and even lost-in-hole (LIH) scenarios. The root causes of problems during this project in the Mulichinco formation were determined to be hole cleaning, weight transfer, and vibration; this paper describes the evolution of drilling improvements based on real-time and post-well analyses.
A holistic approach was necessary to understand the evolution and interaction of each aspect of the operation, from well planning to drilling the well. All information collected and analyses performed were shared with other involved parties to continue the improvement process. The effects of various changes that were implemented were evaluated, and those that had a positive effect were replicated where possible.
During two years of tight sand well operations, the three primary problems included hole cleaning, weight transfer, and vibration. Hole cleaning was improved by closely monitoring the real-time equivalent circulating density (ECD) and torque and drag (T&D), and by adjusting the surface parameters accordingly. Comparing real-time data with the expected simulation outcomes helped to identify the optimum parameters to be used. At first, to mitigate vibration, vibration mechanisms were identified, and surface parameters were changed in an unsuccessful reduction attempt. It then became clear that the problems were associated with the BHA design, and simulations were necessary to identify the problems. Similarly, simulation results were complemented with real-time and recorded data analyses. The weight transfer problem was much more difficult to resolve. A wide variety of information was collected, including visual observation of abnormal wear in drillpipes, comparison of ROP in wells with different BHA designs, and simulations to determine the optimal positioning of the BHA and tubular components. Taking all of this information into account, adjustments were made, and weight transfer gradually improved. These combined improvements resulted in the elimination of LIH scenarios, reduction of unplanned trips caused by tool failures (primarily rotary steerable), and an average reduction of 55% of the time required to reach total depth (TD), from approximately 41.5 days to 18.5 days.
The guidelines described in this paper contribute to the technical optimization of tight sands drilling because they can be used to implement a learning curve process that is applicable for similar operations elsewhere.
Deliquification in a Mature Gas Field: Comparison of Predicted and Observed Rates after Well Workover to Install Velocity Strings
Authors: Burford J. , Falcone G. 
Published: May 2017

Abstract
Liquid loading is a significant issue within gas and gas condensate wells, resulting in production decline and rate instability. The Southern Gas Field serves as a case study, to investigate a field experiencing liquid loadup. The field is located in the Southern North Sea, and is being produced via natural depletion with no pressure support from the surrounding aquifer. In Yr. 9 production well A ceased to flow as a result of liquid build up, and by Yr. 11 well B also showed signs of liquid loading. The load fluid consisted of liquid condensate, and this was confirmed by wireline investigations. A decision was made by the operator to deploy two 2 3/8" velocity strings, in an attempt to extend the field lifespan, by restarting well A and returning rate stability to well B. Velocity strings are a relatively low cost deliquification method, that aim to increase the gas flow rate above the critical flow rate, enabling the well to continuously unload liquids. The design of velocity strings is crucial, as if too small a tubing is used, the velocity string can act as a choke, suffocating the well. The velocity string run in well B proved a success, however the workover in well A failed to restart the well. Batch foamer treatments were later tried in well A but proved ineffective. The effectiveness of foam to deliquifying gas wells, depends upon the composition of the load liquid, as both water and liquid hydrocarbons react differently to surfactants. Typically liquid hydrocarbons such as condensate do not foam well, and must be agitated to maintain foaming.
This study aimed to make use of Petroleum Experts Integrated Production Modelling (IPM) software to model the effect of the velocity string deployment, with regards to returning rate stability. Prosper models were created and Systems Analysis was performed and confirmed that 2 3/8" velocity strings will lift both well A and well B out of the Turner region. Prosper was also use to model the effect of using foam as an artificial lift method, with the results identifying that the water gas ratio (WGR) of the field is too low for effective deliquification using foams. A GAP model was also created for the Southern Gas Field to determine the incremental reserve gains to be had by deploying velocity strings. The simulations identified that well workovers can provide an additional 4.99 Bscf to the recoverable reserves.
Application of Transition Metal Nanoparticles in the Streams Production of Heavy Crude Oil Treatment: H2S Mitigation
Authors: Martinez S. I. , Bastidas C. 
Published: May 2017

Abstract
The in-line scavenging of hydrogen sulfide is the preferred method for minimizing the corrosion and operational risks in oil production (Rajagopal et al. 2009). On the other hand, it is known that Nanoparticles by their small size and high dispersion increase the probability of collision between molecules and minimize the diffusion problems. Additionally, oxides of iron, manganese, zinc, magnesium and copper are considered suitable sorbents for gas desulfurization at temperatures in excess of 300°C (Husein et al. 2010). The experiments were designed to apply nanoparticles for the streams treatment during enhanced heavy oil recovery (steam injection). Sorption of the H2S present in oil phases finds application for mitigating H2S forming during this process. In this study, our heavy crude oil whose viscosity is 10500 mPa.s, was obtained from a reservoir block of the Faja Petrolífera del Orinoco Hugo Chávez (FPOHC, Venezuela), with temperature about 80°C, and when the steam is injected temperature reach up to 260°C. Three types of nanoparticles were used to treat the heavy crude oil (H2S scavengers and reduce viscosity). The organic matrix was high vacuum gas oil (HVGO) which serves as the carrier of dispersed particles, to reduce both H2S production and viscosity, and the nanoparticles, based on transition metals that serve as H2S scavengers centers are, respectively, FexOy, CuxOy and NixOy. In these experiments, before reaction, the sand and the gaseous products were separated to remove any catalytic effect from the minerals and H2S present. Experiments were carried out in an autoclave reactor simulating steam injection condition (~600 psi and ~260°C). Appropriate quantities of heavy crude oil and water, and 500 ppm of dispersed nanoparticles were placed in the reactor; methane was used as reservoir gas. Results indicate the reduction of H2S production from 1500 ppm in the experiment without nanoparticles up to 100 ppm, 250 ppm and traces to FexOy, NixOy and CuxOy, respectively. Also, reductions of viscosity were obtained for all tests, from 15 to 26%.
Extra-Heavy Oil Viscosity Estimation Using PVT and Geochemical Analyses: Applications at Huyapari Field, Orinoco Heavy Oil Belt, Venezuela
Authors: Landaeta G. S. , Valencia L. E. 
Published: May 2017

Abstract
Huyapari is a giant field, located in the Orinoco Heavy Oil Belt of eastern Venezuela. Huyapari contains huge original oil in place (OOIP) of extra heavy crude oil (7 to 9°API) with excellent reservoir properties that enable primary production of the extra heavy crude oil by using long horizontal wells. Nevertheless, the live oil viscosity variation at reservoir conditions (1,500 to 20,000 cp) represents a production challenge in the field. This study aims to improve the fluid heterogeneity understanding in the field through the application of PVT (Pressure, Volume and Temperature) and geochemical analysis for oil viscosity estimation.
Fluid heterogeneity mapping using crude fingerprint analyses was performed to understand the variability of the oil biodegradation level across the field. PVT data provided reservoir GOR and supported the oil chemical variation. Biomarkers correlations were also evaluated to obtain a better estimation of oil viscosity, and then compared with oil viscosity measurements performed at surface and reservoir conditions.
The integration of geochemical analysis with the PVT data allowed to improve the Huyapari field correlations used for well potential estimation. A shallow reservoir of the field with few production wells and larger prospective areas was chosen to evaluate its oil viscosity variation and the methodology application. A better well placement and reservoir management strategy was established, thus demonstrating the value of this data integration.
This study demonstrates that reservoir geochemistry coupled with reservoir engineering data is a cost-effective reservoir management tool. This methodology could be useful for application in other extra-heavy oil fields where little reservoir geochemistry input has been considered in their field simulation procedures.
Are We Reasonably Certain that Reasonable Certainty Adequately Defines Uncertainty in Our Reserves Estimates?
Authors: Harrison B. , Falcone G. 
Published: May 2017

Abstract
Words can have many meanings, while numbers tend to have only one, so using the language of probability can better communicate the potential risks and uncertainties in developed oil and gas projects, which all employ uncertain forecasts of time, hydrocarbon price, cost, and reserves. Yet, rather than assign a probability value to the Proved or 1P deterministic estimate, SPE's Petroleum Resource Management System (PRMS) uses loosely defined expressions such as "reasonable certainty" to convey a high degree of confidence that the deterministically estimated hydrocarbon volumes will be recovered.
A literature review is conducted to highlight what biases people are prone to, and to reveal what people consider to be reasonable certainty. The study recounts the provenance of the phrase "reasonable certainty" in the oil and gas industry. Using published work on cognitive bias by acknowledged oil and gas consultants, drawing on research by Harvard University statisticians, and carrying out our own tests on industry professionals, the authors demonstrate that there are consistent, and quite different perceptions of the language of quantitative probability from those suggested in the PRMS.
Tests show repeatedly that industry professionals believe the probability value that corresponds to "reasonable certainty" is in the range 70-75%. This is far less than the implied 90% figure assigned to the probabilistic low estimate of recoverable volumes, generally taken as equivalent the 1P deterministic case. The divergence between deterministic language and associated and perceived probability is more pronounced when one considers the other reserves classes of 'Probable' and 'Possible'. Such perceptions lead to overly optimistic expectations and can result in poor investment decisions. There is a reluctance to assign probability values to deterministic reserve classes, but that should not prevent the assignment of more appropriate language within PRMS.
Project team members, experts, and stakeholders must be aware that they are all prone to cognitive bias, which when coupled with overly optimistic perceptions of uncertainty, leads to wrong decisions being made, and to projects being mismanaged.
The PRMS text could be changed to better describe the likelihood of the outcome of an event. The continued overuse of the loosely defined adjective 'reasonable' should be avoided. To convey probability greater than 90% or to describe the Low or Proved 1P case, the PRMS would better inform its users by using expressions like "very high probability", "almost certain", or "very likely".
A Practical Numerical Approach for the Determination of Flow Contribution of Multi-Zones Wellbores
Authors: Tarom N. , Hossain M. 
Published: May 2017

Abstract
In these downturn oil price occasions, the establishment of a numerical model may become a reward in the continually on-screen tracking of the challenging issues such as evaluation of zones flow contribution; investigation of alternative methods in lieu of well interventions and prediction of wellbore temperature profile in the operation of multi-zones producing wellbores.
The new approach is based on energy, mass and momentum balance equations. The study briefly describes calculation of overall heat transfer coefficient which is based on the heat resistivity of different layers around a wellbore as well as the heat difference between wellbore and surrounding ground. A simplified numerical model is developed based on the overall heat transfer coefficient which accounts all modes of heat transferring mechanism. The model has been designed to predict wellbore temperature profile along a multi-zones production wellbore. The model explores wellbore temperature profiling both for single-phase and multi-phase production scenarios.
The proposed model has been run for the prediction of wellbore temperature profile for a published oil producing well perforated along three different intervals with the contribution of all intervals in the production. Predicted temperature profile is successfully applied for the investigation of flow contribution of each layer considering key thermal characteristics of single- and multi-phase fluid flow along the wellbore. The predicted temperature profile has been compared with the real data; and a good agreement is demonstrated. This is important as it demonstrates that the proposed model can predict wellbore temperature distribution on a real-time basis to continuously monitor downhole temperature without performing well intervention or installing mechanical tools.
Also, to explore the impact of flow rate and production string size on the wellbore temperature profile, sensitivity analyses have been carried out. It has been found that both flow rate and production string size may have a significant influence in the prediction of wellbore temperature profile. The major conclusion of sensitivity analysis of this study is that the higher production rates and smaller tubing sizes results a higher wellbore and wellhead temperature, which can be as a consequence of friction effect along the producing string.
The novelty of this study is to develop a governing equation as well as to develop a computer simulator for evaluation of wellbore temperature and flow profiles along multi-zones producing wellbores both accurately and quickly. As a result the study may turn aside the necessity of performing well intervention and downhole sensors installation which may significantly reduce well intervention risks and costs.
Five Years of Drilling with Casing in Argentina and Bolivia. Lessons Learned from the Field
Authors: Espinosa C. , Codega D. , Caglieri A. , Grill S. , Guttner H. , Roldan C. 
Published: May 2017

Abstract
Drilling with Casing (DWC) has been used in over 500 strings in the last 5 years in Argentina and Bolivia. The objective of this paper is to summarize the experiences and share the lessons learnt in those years from the perspective of casing connections manufacturer.
Within this paper several cases where drilling with casing technology has been used in Argentina and Bolivia. For each case there will be an explanation of the drivers behind the use of the technology, the challenges that arose during the field implementation and the lessons learned. Special attention will be given to the casing connections, the tools and services required and the limitations.
In Argentina and Bolivia drilling with casing has been used in extensively, in mature fields and shale applications. In all cases the objective was to reduce cost and improve efficiency during drilling. However the drivers where not always identical, in some cases the technology aimed to overcome drilling difficulties as wellbore stability and circulation loss; in others reduce NPT and increase efficiency.
The analysis of the experiences with drilling with casing technology indicates that there are two critical stages for the project: engineering and field operation. In the first, the analysis of fatigue, torque and buckling shall be done properly to reduce risks and hazards, being fatigue the less known and more difficult to assess. Regarding the second, the experience shows that improper handling and use of connections could lead to sudden and unexpected failures compromising the project sustainability. The results are summarized in a list of recommendations.
The experiences from the field have led to the development of specific tools and services aimed to extend the benefits of the technology to other areas. Furthermore, the data collected will shape the design of next generation of casing connections.
A guideline to select and operate casing connections in drilling with casing applications based on extensive field experience.