bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimization and Enhanced Productivity Study in the Furrial Field
Authors: Peretti Leiva F. C. , Gonzalez S. J. , Zabala C. L. , Molina G. , Rondón A. K. , Jeschke Z. A. , Camejo M. 
Published: May 2017

Abstract
Located in eastern Venezuela, the Furrial field is composed of three main reservoirs. Reservoir characteristics include 8,300 million barrels of original oil in place and a hydrocarbon column consisting of crude with asphaltenes that vary from 10 to 30° API. The field has 147 active wells, of which 45 are water-injector wells and seven are gas-injector wells. Wells drilled in the area range from approximately 12,000 to 17,000 ft. Crude oil with asphaltenic tar mats (because of its chemical features) was identified in the field, which establishes a vertical structural seal bordering traditional reservoirs. Major problems in the reservoirs include emulsions, paraffin and asphaltene plugging, water cuts, and water channeling. For several years, the operator has been developing a program to convert wells that cannot be produced naturally to gas-lift wells (conventional, tubing punch, and coiled lift) to increase recovery potential. Although the system is a single, economic, and fast-lifting system, it requires a continuous flow of high-pressure gas.
The productivity workflow presented in this paper required a multidisciplinary team to analyze, select, and rank recommended well candidates for intervention and production optimization, evaluating all aspects pertaining to well productivity and reserves to objectively identify possible alternatives for increasing production. The process produced a list of wells ranked by their potential to increase production. The intervention plan for the wells were then defined and ranked based on technical and economic criteria.
This paper presents the successful application of this methodology in a mature field in the Venezuelan Oriente Basin and demonstrates how the method impacted and improved well productivity in this field by over 27 times more than the base case.
Multipay Well Completion in Argentina: A Versatile Pinpoint Completion Technology Applied through Several Conventional, Tight, and Shale Reservoirs
Authors: Bonapace J. C. , Kovalenko F. , Sorenson F. , Forni P. , Capsa Grupo , Barbalace F. 
Published: May 2017

Abstract
Many fields in Argentina have multilayer reservoirs that require various stimulation techniques, primarily hydraulic fracturing. A variety of formations and types of reservoirs, such as conventional (mature fields) and unconventional (tight gas and shale), are the main focus in the Golfo San Jorge and Neuquén basin. The hydraulic fractures created in these basins present a variety of conditions and challenges related to depth, well architecture design, bottomhole temperature (BHT), reservoir pressure, and formation permeability.
In 2006, a pinpoint completion technique was introduced to help achieve greater efficiency and reduce time and costs associated with completions. This paper presents experiences gained using this technology and proving such versatility in different types of reservoirs.
The pinpoint technique, called hydrajet perforating annular-path treatment placement and proppant plugs for diversion (HPAP-PPD), was applied in new wells at different reservoir conditions. The history and evolution of this technique in Argentina was initiated in conventional oil reservoirs (mature fields in Golfo San Jorge) and then was introduced in the Neuquén basin in gas well completions. Throughout the last seven years, this technique has been tested and implemented in tight gas wells. More recently, it was used to improve a completion technique in a shale oil well.
This completion method allowed operators to focus treatments in desired zones using specific treatment designs based on reservoir characteristics. Several case histories are presented for different basins, formations, and reservoirs types, highlighting lessons learned and reduced completion time.
Fully Compositional Integrated Subsurface-Surface Modeling for Critical Gas Condensate Reservoirs: Santa Barbara and Pirital Fields, Venezuela.
Authors: Pérez J. G. , Cabrera C. J. , Lopez L. R. 
Published: May 2017

Abstract
This paper presents the workflow and learned lessons during the construction of a fully compositional integrated subsurface/surface model for the Santa Barbara and Pirital fields, which are important oil production units located to the east of Venezuela. In this approach, the numerical reservoir simulation models, wells and surface facilities were coupled in order to obtain production profiles considering both changes in the reservoir conditions and surface restrictions, achieving an assertive planning of asset development.
The applied methodology is based on the construction of more than 150 compositional well models, performing sensitivity analysis to define multiphase flow correlations for vertical pipe and chokes. A network model, which comprises more than 900 Km of lines, 3 main flow stations, and 3 separation levels, was also built in compositional mode honoring line sizes, lengths and elevation changes. Two numerical simulation models represent the most reliable characterization of the main reservoirs. Each model was initialized and ran separately, in order to discard internal inconsistencies. Then, the integration was performed considering the sand face on the wells as the coupling point.
The integrated asset modeling allowed predicting the production behavior of the reservoirs taking into account the constraints of the surface facilities, reducing the uncertainty of forecasts and identifying limitations and bottlenecks at surface level. It was also possible to accurately determine the details of the hydrocarbons streams (NGL) at different pressure stages of the network, which reasonably matched with field data (less than 3% of difference). The result is a versatile tool for the integrated asset management, which allows to sensitize all the elements of the production chain and estimate how each one affect the performance of the asset, discarding the division between departments upstream and downstream and establishing a common management strategy for all disciplines.
The novelty of this work is based on the challenge of building fully compositional coupled models considering giants and complex reservoirs with large surface networks. The proposed methodology and learned lessons will certainly serve as reference for similar future works.
Study of Nanoparticle Adsorption and Release in Porous Media Based on the DLVO Theory
Authors: Abdelfatah E. R. , Kang K. , Pournik M. , Shiau B. , Harwell J. , Haroun M. R , Rahman M. M. 
Published: May 2017

Abstract
Nanoparticles are usually small enough that they can pass through the porous media without mechanically plugging the pore throats. However, physicochemical interaction between the nanoparticles and the pore walls can cause significant retention of nanoparticles. The objective of this paper is to provide theoretical equations based on DLVO theory to calculate the rate of deposition and release at different temperatures, ionic strengths, and pH values.
DLVO theory is used to understand the interaction between nanoparticles and rock minerals. Electrostatic interaction depends on the zeta potential of nanoparticles and pore surface. In this paper, an equation is developed to calculate zeta potential at different temperatures, ionic strengths, and pH values. The rate of deposition and release of Silica nanoparticles in a sandstone formation, where interaction energy profile has energy barrier, has been derived. To validate the theoretically calculated rates, a numerical model is developed to compare the theoretical calculations with experimental data.
Increasing ionic strength and temperature decreases the energy barrier height and hence increases the rate of deposition. The effect of pH on the rate of deposition depends on the location of environment pH with respect to the isoelectric point of nanoparticles and rock surface. For extreme values of pH, energy barrier exists and rate of deposition is low. However, when the pH of the solution is between the isoelectric points of nanoparticles and rock surface, the energy barrier decreases and the rate of deposition increases. The rate of deposition is time dependent with the rate decreasing as more rock surface is covered by nanoparticles. These theoretically calculated rate values are used in a numerical model of the advection-dispersion equation with source/sink term. Several experimental data have been perfectly matched with the model that validates the theoretical calculations of the rate of deposition.
The new mechanistic model for nanoparticles can be used to determine the fate of nanoparticles in porous media under different conditions of nanoparticle size, temperature, ionic strength, and pH. This model can help to understand the nanoparticles transport in porous media and effectively design nanoparticles fluid for injection into oil and gas reservoirs.
Grimbeek2: First Successful Application Polymer Flooding in Multilayer Reservoir at YPF. Interpretation of Polymer Flooding Response
Authors: Juri J. E. , Ruiz A. M. , Pedersen G. , Pagliero P. , Blanco H. , Eguia V. , Vazquez P. , Bernhardt C. , Schein F. , Villarroel G. , Tosi A. , Serrano V. 
Published: May 2017

Abstract
Here we report the key success factors of the first polymer pilot at YPF in the south of Argentina and the consensus shifting strategy for polymer expansion in the current oil price context.
We calculated water flow velocities in the reservoir using three multiscale history matched simulation models. We found that more than 80% of water velocities across the complete field are below1ft/day [normally assumed reservoir water velocity for calculating the resistance factor in laboratory experiments].We increased polymer concentration in 10 to 30% to ensure good mobility ratio in the high permeability streaks possibly located in the channel bars. This is very important because low end point water permeability (&lt;0.09) could explain the success of water flooding in friable formation with viscous oil. This challenges the common assumption of poor performance because adverse mobility ration (&gt; &gt; 10). High permeability streaks (above 10 Darcy) are not characterised because they are often lost during coring or they are not suitable for coreflooding experiments. Instead, stochastic history matching supports the idea of greater water end point permeability (&gt;0.2) in the high perm streaks. Then, the target resistance factor for polymer could be underestimated (underestimation of polymer concentration) and polymer injection might not perform as expected. Simulation-based analysis of flows in the pilot zone strongly suggests that one of the key success factors was pattern confinement. The pilot configuration is five-spot with 4 injectors, 1 confined producer and 9 offsets producer wells. After injecting 0.15 pore volumes of 2500/3000ppm polymer we recovered more than 11% ooip incremental oil above waterflooding from the central pattern and more than 6% of the ooip from offset producers in contacted zone. The water cut reduced from 90% to 45% in the confined producer and from 87% to 67% in the offset producers. Water cut reduction and therefore the oil response is greater than best pilots in the literature. This can be explained because of the cross flow between fluvial layers in the inter-well region. Our simulations indicated that there was no out-flow of the central pattern. The very good performance in terms of low utility factor obtained so far (2.9 kg per incremental barrel of oil above water flooding) supports the hypothesis of the good confinement. The accurate simulation model allowed us to conceptualise a pattern rolling strategy for the polymer expansion that makes this technology economic for this low oil price context.
Reversing Well Failure Trends in Shushufindi Increases Production and Reduces Costs through the Application of New Operating Practices and Technologies
Authors: Gozalbo E. , Rodriguez J. C. , Carrera J. , Marquez D. , Meza D. I. , Gornescu B. C. , Reyes D. , Leon R. 
Published: May 2017

Abstract
The giant Shushufindi (SSFD) field, located in the Amazon basin of Ecuador is a mature field that has been producing since 1972. In December 2011, management of the field was awarded to Consorcio Shushufindi (CSSFD) by PetroAmazonas EP (PAM) with the signature of a 15 year integrated services contract. At the time of contract signature, field production was 45,000 BOPD from 90 wells. Since then, 109 new wells and 91workovers have been completed by CSSFD, raising production to 90,000 BOPD in early 2016.
Along with the implementation of a field development plan, key elements, such as the deployment of new processes, operating practices, and technologies, to address deferred production were identified. Production challenges in SSFD were increasing in frequency and severity, and the need for frequent well reviews became a priority.
The processes implemented targeted the reduction of production deferment due to well downhole failures by identifying the root cause, planning for remedial actions, and following-up on execution. An initial field-wide evaluation of production deferment causes allowed implementing the process at a large scale rather than on a well-by-well basis. Project management was applied to prioritize actions and materialize the savings in production and costs.
To accelerate implementation, a pragmatic approach based on experience was initially used, after which the process became fully defined and documented. Main areas tackled were Electrical submersible pump (ESP) design and new technologiesTubing design and selectionProduction chemistry program adjustmentsWell monitoring and surveillance using operation support centers (OSC)Well servicing (pulling) operational efficiency
The improvements were followed by the collection and analysis of field data and results for a period of 5 years and have resulted in an increase in average well run life of over 1 year. Production deferment related to well failure was also decreased from 4.7% to 1.6% of total production, increasing the oil recovery by 1.3 million STBO.
The evaluation of the improvements was done over a period of 5 years (January 2012 to November 2016) where the field data was good enough to carry on the analysis.
Tackling the Challenges of a Mature Field with Multiple Oil-Water Contacts Generated in Major Reservoir Hydraulic Units: Case Study in the Shushufindi-Aguarico Field, Oriente Basin, Ecuador
Authors: Naranjo M. A. , Freire J. L. , Lafournère J. P. , Pastrana W. , Hurtado J. , Bourge J. P. , Vargas A. , Cortez O. , Bringer F. , Izurieta A. 
Published: May 2017

Abstract
The Shushufindi-Aguarico field (SSFD), located in the Oriente basin of Ecuador, has been under production since1972. In December 2011, when Consorcio Shushufindi (CSSFD) joined efforts with the national oil company PetroAmazonas EP (PAM), there were about 150 wells in the field with a production of 45,000 BOPD. Since then, 109 new wells and 91workovers have been completed in the field, raising the production to 80,000 BOPD by August 2016.
Reservoir characterization of the SSFD field was undertaken with sequential objectives in mind. First, to answer the project needs for primary recovery, the effort focused on the main reservoirs (Lower U and Lower T) to create the annual work plans for the initial years of the project. Thereafter, a more refined petrophysical analysis, production data re-evaluation, and individual well diagnosis for water production provided the necessary characterization results for the field development plan (FDP) with a thorough mapping of the hydraulic units (HUs). In Shushufindi-Aguarico field, stratigraphic compartmentalization occurs when flow is prevented across sealed boundaries within the reservoir. These boundaries are caused by a variety of geological and dynamic factors.
The characterization of the heterogeneity in the U and T reservoirs was a key starting point in understanding how lithology controls the horizontal and vertical movement of fluids, the reservoir depletion mechanisms, and the different completion options for a specific well.
Designing Environmentally Conforming Drilling Fluids: Challenges and Considerations in Latin America
Authors: Fornasier F. C. , Campo M. , Djuric A. , Obando D. M. 
Published: May 2017

Abstract
When planning drilling operations for an oil or gas well, drilling fluid is a key factor to consider for a successful operation. Fluid selection depends primarily on two aspects. First, it must meet all specific technical requirements for the well. Second, it must comply with environmental regulations. Therefore, this selection should be evaluated in detail through specialized laboratory testing and engineering analysis. Factors, such as chemical selection, engineering, processes, and field execution contribute to both the conformance and performance of a drilling fluid.
Technical requirements for a drilling fluid are distinct for each operation. However, in general terms, a drilling fluid should ensure wellbore stability, optimize drilling rates, provide effective hole-cleaning rheological properties, minimize pressure spikes while circulating, and transmit hydraulic power to downhole tools. Environmental requirements are region-specific and vary in terms of complexity, from relatively simple guidelines to manage parameters, such as ionic concentration limits, to specific chemical qualifications, such as bioaccumulation, biodegradation rates, and toxicity thresholds. To satisfy both technical and environmental requirements, fluid designs should be fine-tuned and customized in each region.
A principal drilling operation objective is to minimize safety and environmental risks. As a result, operators and service companies take proactive initiatives to help minimize the likelihood of these risks during drilling operations.
Personnel involved in drilling operations should know and comply with the directions in the drilling permit to help avoid environmental and safety incidents. Additionally, all personnel are encouraged to report potentially hazardous activities or circumstances through a variety of observational safety programs.
The purpose of this technical paper is to provide knowledge for the oil and gas industry to help understand the governmental permissions in the Latin American region and considerations for selecting ecologically compatible drilling fluids and products in the region.
Integrated Services in Well Construction Collaborate to Reduce Well Delivery Time by 45% in the Carabobo Area, Orinoco Oil Belt in Venezuela
Authors: Pabón C. A. , Hernandez O. A. , Plazas I. , Urbano E. 
Published: May 2017

Abstract
Billions of barrels of extra-heavy crude oil and bitumen deposits are present in Venezuela, with most located in the Orinoco Oil Belt (OOB). The OOB, which is situated in southeastern Venezuela, is one of the largest, essentially untapped, oil accumulations in the world. The belt stretches 700 km from east to west to the north of the Orinoco River, with an area of approximately 54 000 km2. The OOB is composed of soft, unconsolidated reservoir sands dating from the Miocene age.
The Carabobo block extra-heavy oil reservoirs are categorized by three gross intervals—Lower, Middle, and Upper Morichal formations—which are at a shallow true vertical depth (TVD) of less than 3,500 ft and consist of abrasive sands. Development is typically through the use of extended horizontal wells. Cuttings bed circulation and removal is one of the main challenges in these well types and can normally be alleviated by increasing rotation speed, but the abrasiveness of these formations could cause additional vibration, wear, and/or damage to directional tools.
In a coordinated effort, the operator followed several steps to apply best drilling practices in this area. The first phase was implementing a customized project management (PM) model that organized discrete drilling service contracts under a centralized structure. The ultimate purpose was to drill wells faster in a safe environment with the least nonproductive time (NPT) possible, delivering the wells to production while maximizing efficiency in the field.
Handling Decommissioning and Restoration Liabilities within PRMS and their Impact on Reported Reserves of Producing Fields Approaching Abandonment
Authors: Harrison Bob , Falcone Gioia 
Published: May 2017

Abstract
It is estimated that nearly 150 fields may cease production by 2020 on the United Kingdom Continental Shelf (UKCS), requiring tens of billions of dollars to be spent on decommissioning and restoration (D&R) to remove platforms and development wells. Unfortunately, SPE's Petroleum Resource Management System (PRMS) offers limited guidance on how to handle D&R liabilities, even though such costs impact on whether late-life producible hydrocarbon volumes from a mature field can be classified as reserves.
The economic limit test (ELT), which ignores any costs related to abandonment, is described in the PRMS as the date when net operating cash flow (NOCF) becomes negative, and it defines the reserves to the end of commercial producing life. However, with the agreement of government regulators, some North Sea field operations continue at negative NOCF to defer abandonment expenditure (Abex) and to maximize recovery. Therefore, a discontinuity can occur when subsequently calculating the point forward net present value (NPV) of the developed project, which must include D&R costs, and which leads to the developed project's NPV becoming negative, even though there is a positive ELT to some future date. Recoverable hydrocarbon volumes must be commercial to be classified as reserves, so we have an increasingly common state of affairs where mature fields in the North Sea continue to produce, but should perhaps be reclassified as contingent resources. Operators will find it far more difficult to get loans from banks or attract investor funding if their reserve base is eroded. The PRMS has an implicit, but unstated assumption that the operators of developed projects have arranged financing for D&R liabilities, yet some operators of mature producing fields, who are stil negotiating such cover, argue that the tail-end produced volumes can be booked as reserves in accordance with the vague guidance in the PRMS.
The paper discusses this discontinuity between ELT and point forward NPV, as well as issues around abandonment in the region, methods to finance D&R and safeguard against default, differing views of how D&R costs should be handled within PRMS, and their impact on project classification. The definition of D&R within PRMS is critically reviewed, with formal responses solicited from the SPE Oil & Gas Reserves Committee (OGRC). Finally, the paper suggests changes to the PRMS are needed to make it more suitable for characterizing mature assets that are approaching abandonment.