bluuebunny/crossref_metadata_2025_split huggingface dataset:
CSS Performance in Sands of Samaria Tertiary Field, Mexico
Authors: Aguilar Maria G. , Robles Eliseo Mares , Cabra Garduza Carlos M. , Peralta Oscar Osorio 
Published: September 2014

AbstractIn this paper shown the results obtained in the Extra – Heavy Oil Samaria Tertary Field by Ciclic Steam Stimulation (CSS) along almost 6 years. We have identified the major variables affecting the process; the thickness of the sand has been identified as the principal parameter to affect the performance of CSS process. It has been found that the temperature decline in thermal production from 35 days to 200 days. For thin thickness loses energy about 40% and for net thickness upper 15 m loses energy about 10% from overburden and underburden formations.Our primary interest was to optimize present operations and to find infill wells. Actually the recovery factor is 2.3; with the development plan has optimizate with the understanding of the CSS performance in the field, with recovery factor increment from 6.93 to 8.8 in the next three years.
Fluid Characterization and Flow Improvers Evaluation for Samaria Somero Field
Authors: Cruz-Andrade J. P. , Cabra C. G. , Mares E.. , Ramirez Jaramillo E. R. , Echavez-Ross G.. 
Published: September 2014

Abstract
Samaria Somero field produces heavy and extra hevy oil. To mitigate the fluency problems present in this kind of fields is necessary to constantly evaluate chemical improvers such as Water-Base Flow Improvers (WbFI) and Oil base Flow Improvers (ObFI). The first type of improvers works by creating emulsions which generate partial solubility between the oil and water phases. The second ones focus on lowering the viscosity. The objective of both systems is to increase the fluency through the oil transportation process. These types of chemical systems are usually tested on the field, measuring its efficiency through the injection of different amounts of product to the wells, evaluating the oil production increments and wellhead pressure drops, during the injection of the enhancer. Because the parameters to evaluate the efficiency and compatibility can not be rigorously controlled on the field test, these assessments can be misleading, since the response of the well could be attributed to the chemical or how the well is operated. So it is not possible to evaluated and quantigy clearly the phenomenon that occurs when mixing a WbFI or ObFI with crude.
Given that field test have no strict control on the variables to assess the efficiency and compatibility of WbFI and ObFI, PEMEX in conjunction with the Mexican Petroleum Institute (IMP), developed an experimental methodology to evaluate these products with experimental tests.
The purpose of this paper is to show the results of laboratory analysis for the Samaria Somero fluid characterization process and present a new methodology to exam the Flow Improvers evaluation, which was used to evaluate 5 different companies' products in the market.
Charge Pump for Gassy Application Venezuela Faja Del Orinoco
Authors: Arredondo Manuel , Moreno Octavio , Delgado Javier , Soltys Tim , Svitich Jason , Dunn Lonnie , Bettenson John , Noble Evan , Gonzalez Juan Carlos 
Published: September 2014

Abstract
One of the major impacts on progressing cavity (PC) pumps is the amount of free gas that enters the pump intake. PC pumps can handle increased amounts of free gas but under certain conditions this can have detrimental consequences on pump life, decreasing pump performance and pump production capacity. The higher the gas rates through the pump the higher the internal temperature. This temperature increase accelerates elastomer degeneration and fluid penetration into the elastomer to the bonding agent. Having a high volume of gas entering the pump decreases the amount of fluid slippage which does not allow for an even pressure distribution throughout the entire length of the pump. This uneven pressure distribution increases the workload to the discharge of the pump causes a premature failure. In order to overcome these issues charge pumps technology was tested.
The study was completed in the Orinoco Belt, Petropiar field. This is an unconsolidated sandstone formation with high fluid flow rate wells, 430 bbls/d at an average of 11° API. Reservoirs change through their productive life varied the operational conditions in the Orinoco Faja wells. Historically intake pressures were higher than 500 psi, GORs average 25 scf/stb resulting in free gas levels lower than 50%. Recently, data shows intake pressure lower than 250 psi, GORS higher than 1000 scf/stb resulting on free gas levels over 90%.
This is the first charge pump installed in Petropiar field. The strategy for this project was to start identifying well candidates where charge pumps can improve the PC pumps performance through gas separation and reduction of gas volume fraction (GVF) at pump intake. It also considered a well facility's conditions in order to get more variables and the most accurate information for this trial evaluation. The overwhelming results after installing the charge pump allowed the expansion of this technology to different wells with similar conditions regardless of well fluid production rate, sand, or water cuts. This is all part of a combined effort for finding reliable and cost effective solutions for challenging applications.
Selection Criteria for Power Generation Systems to Minimise Environmental Impact
Authors: Welch Michael 
Published: September 2014

Abstract
In many countries, Heavy and Extra Heavy oil reserves are located in sensitive environments, remote from existing infrastructure. Heavy oil production is energy intensive, requiring the combustion of fossil fuels to produce the heat and power required. Burning fossil fuels creates a wide variety of emissions to atmosphere, such as the Carbon Dioxide (CO2) released by burning carboniferous fuels to combustion pollutants such as oxides of nitrogen (NOx). In addition, Heavy Oil reservoirs tend to be gas deficient, and often a low cost way of disposing of the small quantities of unwanted associated gas is to flare it, creating a new source of emissions.
The first part of this paper looks at how to minimise emissions from energy production by making best use of locally available fuels, such as associated gas, and employing energy efficient techniques such as Cogeneration. It then discusses how the three most common power generation technologies – gas turbines, reciprocating engines and steam turbines – can be applied to Heavy Oil operations to minimise the impact of fossil fuel combustion.
However, building and operating a power plant or energy facility of any kind, also has other impacts on the environment. There are transportation issues in getting the equipment to site in the first place, the human impact on the environment due to both construction and operation of facilities, the issue of disposal of produced wastes, and the need for continuous re-supply of the power plant with the consumable items and spare parts to keep it operational. This paper therefore also compares the consumable and maintenance needs of the three main power generation technologies to investigate the long term impact of operations on the environment.
Key Issues in Heavy Oil Waterflooding Projects
Authors: Vidal R.. , Alvarado R.. 
Published: September 2014

Abstract
Waterflooding is an improved oil recovery (IOR) method commonly used worldwide. Some of the world's largest waterfloods are found on Lake Maracaibo, in western Venezuela. One such project is the Bachaquero-02 (Bach-02) which was initiated in 1967 as a peripheral water injection in an unconsolidated sandstone reservoir with average permeability of 350 mD and average oil gravity of 15° API. This waterflood project has been the subject of various studies that include conventional assessments, integrated full field and simulation studies. This paper presents a diagnosis of the impact that waterflooding has on Bach-02 heavy oil recovery, in view of a new approach that reveals mechanisms of heavy oil displacement by water. The findings of this field study are in accordance with empirical, experimental and simulation investigations recently reported in technical literature. Voidage Replacement Ratio (VRR) and Water Oil Ratio (WOR) analysis in this reservoir show particular behaviors associated with fluid flow characteristics in the reservoir; namely, periods of VRR less than 1.0 which activate mechanisms that stabilize WOR at values close to 1.0 and result in increased oil recovery. These mechanisms are explained by recent investigations as the flow of water-in-oil emulsions, and in situ formation of foams that benefit from chemical changes brought about by periods of underinjection.
Smart Water Injection for Heavy Oil Recovery from Naturally Fractured Reservoirs
Authors: Gachuz-Muro Heron , Sohrabi Mehran 
Published: September 2014

AbstractEnhanced Oil Recovery (EOR) from carbonate reservoirs can be a great challenge. Carbonate reservoirs are mostly oil-wet and naturally fractured. For this type of reservoirs, primary production is derived mainly from the high permeability fracture system which means that most of the oil will remain unrecovered in the low permeability matrix blocks after depletion. Further difficulties arise under high pressure and high temperature conditions.Oil recovery from carbonated rocks may be improved by designing the composition and salinity of flood water. The process is sometimes referred to as smart water injection. The improvement of oil recovery by smart water injection is mainly attributed to wettability modification in the presence of certain ions at high temperature. The resultant favourable wettability modification is especially important for naturally fractured reservoirs where the spontaneous imbibition mechanism plays a crucial role in oil recovery.The objective of the work presented here was to experimentally investigate the performance of smart water injection for heavy oil recovery from carbonate rocks under high reservoir temperature. A series of coreflood experiments were performed using a group of carbonate cores in which smart water injection was tested under both secondary and tertiary injection conditions. The experiments were conducted at 92 °C using an extra-heavy oil. Seawater from Gulf of Mexico (GOM) was used in the seawater injection experiments and the smart water used in the tests was obtained by 10 times dilution of the seawater. Although concentration of SO42− is lower in the smart water, the occurrence of SO42− as anhydrite in carbonates may be sufficient to stimulate a similar reaction between the carbonated rock and the injected water with lower salinities at high temperatures. Seawater injection resulted in oil recovery ranging between 30% and 40% whereas smart water injection resulted in 60% oil recovery from the same system.Additionally, analyses of brine composition before and after coreflood experiments confirmed that the effluent concentrations of SO42−, Mg2+ and Ca2+ changed compared to its original values in the injected water. The results indicated that, for some cases, the source of these ions was dissolution from the rock surface. The reactivity of the rock increased when lower salinity water was used.
Drilling of Shallow Horizontal Wells at Very Extended Stepouts in the Venezuelan Faja
Authors: Chamat Elias , Peñaranda Juan , Trejo Ely , Meneses Maria 
Published: September 2014

Abstract
The Orinoco Oil Belt or “La Faja”, located in Venezuela, is the biggest reservoir in the world holding heavy and extra-heavy oil stored in highly permeable non-consolidated sands. To maximize reservoir exposure to production from these low pressure reservoirs, long horizontal sections in the reservoir are needed. Because of this, longer horizontal sections are being drilled and will continue to be drilled in the Faja.
The Faja reservoirs dip towards the north where drilling of horizontal wells has been concentrated in the last three decades, in wells drilled to true-vertical-depths (TVD) from 2,500 ft to 4,000 ft. As drilling in the last five years in Faja has moved towards the south, wells have been completed at TVDs from 1,500 ft to 4,000 ft. The recent development of the Junin Division of Faja, in the last two years, has required placing the wells at southern reservoirs at TVDs from 1,200 ft to 1,500 ft. Drilling these shallow horizontal wells demands adequate planning and execution to manage risks coming from high dogleg severities drilled with downhole motors, such as cyclic stresses of bottom hole components, high torque and drag, poor hole cleaning, inadequate weight-on-bit transfer, pipe swaps and stuck pipe events. Despite of the operational limitations seen when drilling shallow ERD wells with motors, a good number of wells recently drilled in southern Faja have reached important regional records of horizontal footage drilled. The current shallow horizontal record was drilled at 1,231 ft TVD; this well also coincides to be a record for Venezuela in terms of horizontal section drilled. The TVD over horizontal step-out ratio, or Extended Reach Drilling ratio (ERD), for this well was 1 to 4.4, which also constitutes a regional record.
After different operators drilled in Junin 28 shallow ERD wells with downhole motors, PDVSA, PetroMiranda and the service company tried out a point-the-bit RSS in three new shallow ERD wells. This paper presents the optimization experience using RSS to drill for the first time shallow ERD wells in Junin Division. An operational and technical comparison of RSS versus motors in Junin operations, as well as progress in the learning curve is also presented.
The experienced gained drilling horizontal sections of 28 shallow ERD with motors and three more wells drilled in the 8½-in. horizontal drain with RSS has become in an important performance step change to start planning drilling new southern blocks of Junin Division, where reservoirs could be as shallow as 1,000 ft.
Geomechanics Coupled Fluid Flow in Heavy Oil Reservoirs Considering Cold Production
Authors: Alvarez L. L. , Alzate G. A. , Naranjo A.. 
Published: September 2014

Abstract
Historically, the geomechanical behavior of a hydrocarbon reservoir has been modeled based on the classical theory of poro-elasticity, which considers absolute reversibility of deformation, which is liable to a porous medium when the mechanical state of the rock is altered. The sands associated with heavy oil formations are generally characterized by low levels of cohesion and density, which is viewed in an increased sensitivity of the rock to permanent deformation and hysteresis; hence it is not suitable to model these formations as if their rheological behavior is elastic. This set the need to construct a model, which describes the permanent plastic deformation that rocks from this kind of reservoir have.
The modeling of the stress-strain behavior of plastic porous media aims to evaluate the permanent deformation that the rock suffers and to study the impact of this phenomenon on the behavior of the reservoir permeability porosity and mechanical stability of the layers overlying (compaction, subsidence). Several theoretical research and experimental surveys have defined that most heavy oil reservoirs can be studied as elasto-plastic materials.
The purpose of this paper is to show the couple model of constitutive equations (stress-strain model) and fluid flow equations that describe the dynamic behavior of a heavy oil reservoir during an isothermal process, which deforms elasto-plastically, and thereby, to predict several geomechanical phenomena or consequence as productivity drop due to changes in the permeability, pore collapse, cap rock integrity, subsidence, among others, that allow an approach to the behavior of these kind of reservoirs in order to improve production processes and simulation.
Reservoir Characterization of Junín Area, Orinoco Oil Belt Region, Venezuela
Authors: Cocco Martín J. , Ernández Jesus E. 
Published: September 2014

Abstract
As conventional hydrocarbon supplies tighten, world energy consumption rises and new technology emerges, unconventional sources of hydrocarbons are increasingly contributing more to the world energy basket. As a consequence, the upstream petroleum industry has more sharply focused its efforts in studying unconventional reservoirs during the last decade, especially those with extra-heavy oil. Most of the reservoirs with extra-heavy oil accumulations are too geographically widespread to be commercially attractive. One exception is the Orinoco oil belt region, located in eastern Venezuela, which contains enormous deposits of extra-heavy oil.
Both international and national oil companies have formed Empresas Mixtas (joint ventures) with Petróleos de Venezuela (PDVSA) to explore and produce lease blocks in the Orinoco region during the last few years. The experience of these joint ventures shows that the extra-heavy oil can be economically extracted with cold production at higher production rates than those observed in other regions with hydrocarbons of similar characteristics (Dusseault, M. B.) The total developed acreage in production by JVs today represents only fraction of the potentially commercial area of the Orinoco Oil Belt, leaving a significant remaining undeveloped region.
The Orinoco oil belt is divided into four areas: Ayacucho, Boyacá, Carabobo and Junín. The authors conducted a detailed evaluation of PDVSA's Junín area reservoir data and revised technical interpretations and reached some key conclusions in the study. This paper summarizes reservoir characterization rationale and procedures and significant study findings, including those addressing assessed volumes of original oil in place and recovery factors.
Maximizing Asset Value by Waterflooding Based on a Hypothetico-Deductive Method for Formulation, Evaluation, and Selection of Exploitation Scenarios. Case Study Lower Lagunillas-03 Reservoir
Authors: Tillero Edwin , Mogollon Jose Luis , Gutierrez Isabel , Peretti Francis , Lujan Luis , Fernandez Enedis , Niño Pedro , Perdomo Carlos , Portillo Jackmary 
Published: September 2014

Abstract
The Lower Lagunillas-03 reservoir, in Maracaibo Lake, Venezuela, has been producing for more than 80 years from La Rosa (25 API gravity) and Lower Lagunillas (19 API gravity) formations. The average pressure is less than a 1/3 of its oil bubble point pressure; whereas more than 70% of the OOIP remains in place.
Several waterflooding projects (Modules) with different injection patterns have been implemented since last 40 years, which have shown different results in term of production behavior and oil recovery. Therefore, an optimal waterflooding scheme has not been identified yet for the fifth waterflooding module (Lower Lagunillas Formation) and also for future waterflooding modules to be implemented for revitalizing the potential of this mature reservoir.
It is essential in this case to ascertain the objective of an optimal waterflooding scheme in order to unlock the promissory oil recovery potential considering current reservoir conditions and financial resources. This was accomplished based on an innovative hypotetico-deductive method, which considers cycles of formulation-testing-analysis-emerging of hypotheses (scenarios), and starts with the formulation of a simple or relevant hypothesis (expectation) about a feasible exploitation plan. It is tested using a numerical or analytical model campaigned with economical optimization workflow and its results inquires to evaluate the hypothesis in the light of initial expectations as discarded or chosen, or whether some emerging hypotheses might be conducted and others might not. In turn, they are cycled until analysis of prediction determines probity of hypotheses or the refined research of hypotheses is stopped.
Contrary to initial expectations, many hypotheses about waterflooding patterns for the fifth module were tested, such as new horizontal injector-producer wells (direct line drive), inverted seven-spot, and inverted five-spot from existing wells. Nevertheless a substantially increased Net Present Value (2 times greater compared to Base Case) was reached by testing inverted five-spot patterns using infill drilling and extending the area to be flooded so that it emerges as a novel strategy for unlock the potential of this mature reservoir.
Mesophase Fluids Treatment: An Alternative to Clean up Heavy Crude Oil Wells in Mexico
Authors: Torres Jorge , Espinoza Juan Carlos , Pietrangeli Gianna , Morales Diana 
Published: September 2014

Abstract
Many different types of crude oils are extracted from Mexican reservoirs, and most of the crude oils from the northern region are heavy crude oil with API gravity between 15 and 20. Many fields in this area are mature and have been intervened as long as 50 years ago. As a consequence, the identification of the damage and selection of the right treatment is challenging for those wells. Furthermore, the type of completion used does not allow the use of production assemblies for intervention.
Traditional treatment techniques consist of reverse circulation using coiled tubing. In the first treatments, the majority used hot oil in cycles and BTEX solvents. Several of the interventions were not successful, and the logistics process was complicated. In some cases, the treatment led to asphaltenes deposition and emulsion blockages in the near-wellbore region.
Mesophase fluids based on microemulsion technology are a viable alternative remediation system for wellbore cleanup when low-producer wells experienced intervention. The fluids are carefully designed, have ultra-low interfacial tension, high oil solubilization, and good compatibility with formation fluids. They can be used to mobilize trapped fluids and solids in damaged wells, remove water blocks and in-situ emulsions, to name a few of their benefits. After many applications in Mexico and other countries, experience shows this fluids technology leads to more productive oil and gas wells because they can be remediated or protected from damage. Mesophase fluids are differentiated from conventional technologies by composition, their mechanism, and application. These novel fluids have low or no aromatics content or other solvents and easily diffuse through the formations. The application of the technology involves a carefully designed treatment train based on pills. The pills circulate from the annulus to the string assembly or reverse circulate to displace the fluids rapidly. The treatment is pumped close to the pay zone, with a radial fluid invasion of 1 to 2 feet into the formation, and then is allowed to soak overnight. More than 20 applications confirm the success of this technology in remediating heavy crude oil wells. In some cases the production increased by a 100%.