bluuebunny/crossref_metadata_2025_split huggingface dataset:
Successful Application of Discontinuous SAGD Technique to Maximize Oil Recovery in Alberta's Oil Sands
Authors: Nguyen Huy X. , Bae Wisup , Nguyen Danh H. , Tran Xuan V. , Ta Dung Q. 
Published: June 2012

Abstract
The steam assisted gravity drainage (SAGD) process has proven to be an effective thermal recovery method for heavy oil and bitumen production. Recently, some innovative techniques based on the background SAGD operation have been applied such as conventional SAGD, Fast-SAGD, Hybrid SAGD, FA-SAGD. However, there has been much dispute over the question of economical efficiency due to high capital investment, operating costs, and the fluctuation of oil and gas prices. The integration of economic and technical aspects for SAGD performance plays an important role in field operation. Main problems to solve are how to design optimal operating conditions for a reasonable steam requirement with certain injection pressure to maximize economic feasibility under reservoir conditions.
The previous literatures implemented sensitivity analysis and optimization of SAGD performance by classical methods based on numerical simulations lead to a lack of confidence level and ignored interactions effects between considered parameters, which may cause low efficiency issues in a field operation. In addition, the SAGD economic model in previous studies have not fully information with limited consideration on few factors. These restrictions can be avoided by the application design of experiment and response surface methodology to determine the optimal operating conditions for the production prediction. Then, discontinuous SAGD technique was operated to control the amount of injected steam at several specific injection time intervals.
This study represented that the discontinuous SAGD performance is applied to three major formations of Alberta’s oil sands. The results showed that both oil recovery factor and economic profit are much higher than other techniques, especially the effective at deeper burial reservoirs of Clearwater and Bluesky formations. Moreover, amount of injected steam and water cut reduced significantly to cause lower operating costs as steam cost, led to increase NPV as well as minimal environmental damages.
Low Cost Production Gains from CHOPS Wells with Extremely Viscous Oils
Authors: Minish Travis , Yule David 
Published: June 2012

Abstract
Production of heavy oil from Alberta’s vast reserves continues to be a costly and capital intensive endeavor. To date considerable research has been focused on mining, SAGD, in-situ combustion, and vapor extraction. A new chemical dispersant technology has been introduced in the past year that reduces the apparent viscosity of the produced fluids from wells in the heavy oil fields around Lloydminster, Alberta, reducing the power required to drive the downhole progressive cavity pumps (PCPs), allowing pumping rates to increase, and increasing daily oil production by up to 300%. The primary benefit is removing the obstacle of pump speed limitation due to high oil viscosity.
CHOPS production suffers from many challenges. Principally, the cold heavy oil exhibits high viscosities, in some cases in excess of 100,000 centipoises (cPs). Over the past two decades, technological advances in downhole PCPs, rod strings, well heads, and power units have improved the ability to produce heavy oils. However, when viscosities approach or exceed 100,000 cPs these advances do not overcome the excessive drag created by the heavy oils as they travel up the production tubing. The newly developed chemistry creates a dispersion of oil in water with a much reduced overall viscosity and increased mobility. The result: more oil loading into the pump, less drag along the rod string and production tubing, lower power requirements, the ability to increase the pump RPMs and, therefore, increased oil production.
This technology was developed in Western Canada and has proven itself to be successful at increasing oil production, improving on-time, and reducing servicing on Canadian heavy oil wells produced by way of cold recovery methods. This technique could be utilized in other heavy oil fields throughout the world where production rates are limited by the issues created by extreme oil viscosities.
A Novel Approach for Determining Wormhole Coverage in CHOPS Wells
Authors: Xiao Lei , Zhao Gang 
Published: June 2012

Abstract
In this study, the comparison of the transient pressure responses of different wormhole patterns has been comprehensively studied. The modeling results show that transient pressure and production responses vary significantly due to different wormhole structures and reservoir area that embeds with the structure. A concept of effective wormhole coverage is proposed for the first time in this study and its corresponding wormhole model has been well established and validated to study the effective wormhole coverage for wells in the process of Cold Heavy Oil Production with Sand (CHOPS).
Type curves developed for CHOPS wells with wormholes in this study can be applied to analyze transient pressure and production data from wormholed heavy oil reservoirs. Effective wormhole coverage and branches can be reasonably estimated using type curve matching. This work helps offer important parameters in further optimization of post-CHOPS processes such as post-CHOPS EOR planning and infill well drilling.
Type curves for effective wormhole coverage with different numbers of effective wormhole branches were developed for CHOPS wells in this paper. Once either the transient pressure data or production data are matched with the developed type curves, the number of effective wormhole branches and match points are recorded. The effective wormhole coverage can be subsequently determined using the equations developed in this study. In addition, once the number of wormhole branches and effective wormhole coverage has been determined, sand production data can be utilized to help determine the diameter of effective wormholes. It should be noted that, prior to the use of the type curves, formation properties and foamy oil properties should be prior known information.
In CHOPS, the presence of wormholes is considered to be one of the most important factors which contribute to enhanced production rate. Due to the complexity of wormhole phenomena, few methods have been introduced to determine wormhole coverage quantitatively. The novel approach presented in this paper is aiming at providing quantitative information of wormholes by analyzing transient pressure, production rate, and sand production data simultaneously.
Sand Prediction by Different Criteria and a Validation by a Perforated Test in a Sandstone
Authors: Wang Y. , Papamichos E. 
Published: June 2012

Abstract
Sand production in a perforated sample is determined by the onset of a significant discrepancy between strains in two orthogonal directions. The onset is also analyzed by three different sanding models, i.e., shear failure, cohesive tensile failure, and the effective plastic strain (EPS) models, respectively. Comparing these results, we conclude that the results with the shear failure criterion provide the most conservative prediction, and the EPS can provide the closest results to the testing one, given adequate plastic yielding and sanding parameters. Comparing with the cylindrical cases (open hole), both the plastic radius and critical strains calculated for the perforated cavity (cased hole) cases are calculated. A critical equivalent plastic displacement (EPD) is proposed as only one additional parameter is required on top of those from a typical elastoplastic model and such a criterion allows us to determine the sanding onset directly, those using stress, strength or strain whereas can only be indicated or interpreted indirectly, yet difficult to measure in practices.
Field Results for Recovering Oil from A Steam Project Pressure Isolation Wall
Authors: Miller Karl A. , Xiao Yi 
Published: June 2012

Abstract
The Lloydminster Saskatchewan area Pikes Peak steam project has been on production since 1982. A key part of the development strategy was use of an undeveloped pressure isolation wall to allow the two halves of the pool to be developed using different time schedules and exploitation processes.
Use of the pressure isolation wall allowed different exploitation options to be used, but during late project life the oil left in the wall needed to be recovered to enhance project economics. A significant challenge to recovery of the oil in the wall was the lack of pressure containment or oil saturation on both flanks, resulting in the need for a very gentle recovery process to avoid pushing the oil outside the wall.
On the basis of numerical simulation results the recovery process selected for the wall was use of two CSS horizontal wells operated in a gentle manner. After the horizontal wells were drilled, however, temperature logs showed the reservoir surrounding one of the horizontal wells had already been heated by offsetting steam injection, and that well has been continually produced at good rates without the need for steam stimulation. The second new horizontal wall well has been successfully operated using the CSS process designed using numerical simulation.
The results of this field study show that the oil in a wall used to pressure isolate sections of a steam project pool can be economically recovered without pushing the oil into the adjacent depleted areas by use of processes designed to account for local wall conditions.
Multilateral and Geosteering Technologies as a Solution for Optimum Drainage of Heavy Oil of Thin and Heterolithic Sands in Junín Block of the Orinoco Oil Belt
Authors: Palermo Jose , Ramos Joel , Jurado Maryuly , Brazon Carmen , Rondon Leonque , Alfonzo Pedro , Bonalde Antonio , Garcia Wendy 
Published: June 2012

Abstract
Petrocedeño is one of the companies that operate in Junín Block of the Orinoco Oil Belt. This block is located on the southern flank of the eastern basin of Venezuela and produces 150 thousand barrels per day from about 700 wells. Exploitation of this field began early in 2000 year, draining the sands with greatest potential (rock quality in terms of thickness and homogeneity). Today, the amount of this type of sand is reduced; however huge reserves still are in this complex reservoir. About 20 wells have been drilled in Unit C2, deltaic depositional environment with average sand thickness ranging from 10 to 20 ft. and heterolitic beds. Due to these characteristics of the sands, production results of these wells are far away from estimations.
Multilateral technology has been used to increase the amount of reservoir exposure in these heavy-oil fields with great success. Sandy problems, observed in most of the 15 multilateral wells drilled in the area, have been solved by cementing the system junction. On the other hand, application of a real-time geosteering technique has allowed a flawless wellbore placement within a reservoir with a challenging stratigraphy and complex sedimentological environment in Junín Block of Orinoco Oil Belt.
Petrocedeño used Multilateral System level 4 together with Azimuthal Deep Resistivity technologies to face this challenge. Multilateral advanced drainage architecture to increase reservoir exposure from a single surface location, minimizing collision risk, and to improve production. And Logging-while-drilling with Azimuthal Deep Resistivity tool in conjunction with specialized modeling and wellbore positioning techniques was used to enable swift reaction to maintain the well path within the reservoir boundaries in these thin laminated sands.
First Multilateral level 4 well was drilled and geosteered in deltaic C2 Unit on November 2011. Geoscientists and drilling engineers worked as a multi-disciplinary team to make the best wellbore trajectory decisions to position YC36 hole into the best zone of the reservoir along of 5,265 feet. This publication will describe application of multilateral and geosteering technologies in YC36 well. Economical analysis will be presented and explained, as well as production results.
Thoughts on Simulating the Vapex Process
Authors: Cuthiell David , Edmunds Neil 
Published: June 2012

Abstract
The Vapor Extraction (Vapex) process and its many hybrid variants have attracted a great deal of attention as potentially less energy intensive alternatives for exploiting heavy oil and bitumen resources. However, despite much work over the past two decades, uncertainty remains about the basic mechanisms, the scaling aspects and the most appropriate methods of numerically simulating these processes. This paper offers some insights into several of these outstanding questions. The questions are examined in the context of an extensive and well-documented set of Vapex experiments carried out by Maini and his colleagues over the past 10 years.
We have experimented with different methods of simulating these experiments using a physics-based reservoir simulator. Despite the high permeability (greater than 200 Darcys in all of the experiments), we find that capillary pressure plays a significant role in the drainage. The simulations suggest that most of the drainage takes place in the capillary transition zone along the edge of the vapor chamber, rather than in the single-phase zone ahead of it which has not yet been contacted by vapor.
It has been emphasized in the literature that the near-linear scaling of oil rate with height observed in the experiments is dramatically different from the square root of height dependence predicted by the original analytic model of Vapex. However, the experiments also show an increasing solvent fraction in the produced oil phase as height increases. When this "solvent mixing" effect is separated out of the rates, the remaining height dependence is less than linear, though still greater than square root of height.
The relative roles of molecular diffusion and mechanical dispersion in Vapex have been widely discussed in the literature. Generally, mechanical dispersion is expected to play a larger role in these high permeability experiments (vis-à-vis the field), due to larger fluid velocities. We present a method of inferring the diffusion/dispersion present in the simulations, despite a hidden component of numerical dispersion caused by the numerical method itself. We find that the experiments are well matched with values of diffusion and dispersion in line with literature correlations, and that the contribution of mechanical dispersion is perhaps not as large relative to that of molecular diffusion as might be expected.
The paper also provides some thoughts on questions we believe are still unanswered, including mechanisms behind the height dependent mixing phenomenon and the scaling of the experimental results to the much greater heights and lower permeabilities characteristic of the field.
PVT Correlations for Trinidad Oil Offshore the Southwest Coast
Authors: Singh T. , Hosein R. 
Published: June 2012

Abstract
Reservoir fluid properties such as bubble point pressure, oil formation volume factor and solution gas-oil ratio are used for the evaluation of reservoir performance and reserves estimation. Laboratory analyses of these properties are not always available and they are best estimated from correlations. The available correlations were developed for both worldwide applications or for specific regions since oil from different regions vary in compositions. In this study correlations by Standing, Vasquez and Beggs, Glaso, Al-Marhoun, Petrosky and Farshad and Velarde et al were tested to estimate the above mentioned PVT data for Trinidad oils offshore the Southwest Coast. A spread sheet was developed for the calculations and the data for the evaluations were taken from twelve PVT reports.
The results show that the Velarde et al correlations gave the best estimate of the aforementioned PVT data for the twelve available PVT data sets. A comparison of the estimated and experimental PVT data show differences of less than ± 7.0 % for bubble bubble point pressures, less than ± 4.0 percent for oil formation volume factors and less than ± 10.0 percent for solution gas oil ratios. These results indicate that the Velarde et al correlations can be used to obtain accurate estimation of the above PVT properties for Trinidad oils offshore the Southwest Coast for future reservoir engineering calculations.
Study of the Success Factors in Continuous Steam Injection: Field Case, Colombian Middle Magdalena Basin
Authors: Trigos E. M. , Rueda S. F. , Rodriguez E. , Espinosa J. S. 
Published: June 2012

Abstract
In Colombia, there are several heavy oil fields where cyclic steam stimulation have been successfully applied for over 25 years and although it is assumed that the reservoir temperature is high and the conditions are ideal for making the leap to continuous steam injection, some studies apparently show that this technique is not feasible for the reservoir; in fact, between 1992 and 1994, the implementation of a pilot did not reach the expected results.
From this fact raises the question: What are the key factors that ensure the success of a continuous steam injection pilot? To solve this question, a numerical simulation and analytical model based study was performed, showing that the performance of the technique lies in minimizing the energy losses and supplying only the necessary heat according to each stage of the process, these practices are known as heat management.
It was found that critical aspects of heat management are: reducing well spacing, selection of open thickness to injection, perforated intervals, completion design, injector well distance from generator and injection surface line conditions, as well as constant reservoir temperature monitoring, from which the energy requirements at each stage of the process is determined and avoid an excessive injection rate which goes against project economics.
For the field case it was found that: the well spacing should be reduced from 10 to 2.5 acres, the need of using selective sequential injection scheme (due the interbedded shale), the injection rate should be reduced to 46% a year after starting the process and also change the type of insulation on the surface lines. In this paper, the methodology and tools used for factor evaluation and process optimization are presented.
Big Bore Expandable Liner Hangers for Offshore and Deepwater Applications Reduces Cost and Increases Reliability: Global Case History
Authors: McCormick J. , Matice M. , Cramp S. 
Published: June 2012

Abstract
Reducing rig time and material costs for offshore wells is critical to a project’s financial profitability. With the dramatic increase in the number of deepwater wells, new technologies and methods are needed to quickly and reliably complete wells. A case history of 14 large-bore expandable liner hangers (ELHs) in the Caspian Sea and one in deepwater Gulf of Mexico (GOM) show consistent material cost savings, reduced installation time, improved reliability, and increased versatility over the conventional liner hanger system.
The technological advances of ELH systems have increased well life and improved safety during liner installations over traditional systems. Sealing capabilities with expandable systems have evolved beyond conventional tools and the smooth radial flowpaths allow for greater ease of installation. A series of redundant sealing elements provide a gas tight liner top seal which stops any possible gas migration. Also, with the ELH system, rotation and reciprocation while cementing are possible.
This paper will describe offshore wells and the common problems associated with them. Expandable liner hanger technology will be explored to increase operator awareness of an additional technology. An in-depth exploration of ELH technology and the comparison of conventional and ELH systems in the same field are described within this paper.
Optimization of Emulsion Breaker Concentration
Authors: Dubay B. A. 
Published: June 2012

Abstract
Emulsion breaker chemistries are important to the efficiency of crude dehydration and the enhancement of primary produced water treatment. Often a number of specifically developed chemistries are used within a single operation: normal emulsion breakers (primary and secondary/slop oil) and reverse emulsion breakers (coagulants and flocculants). These chemistries must be compatible with each other and used at optimum concentrations.
Determining optimum concentrations require three stages: research and developmental chemistry, ‘Bench Top’ bottle-testing of crude and field testing. Of the three stages field testing is the most critical as based on the number of fluid streams, components and varying process conditions often laboratory testing and process modeling alone cannot effectively simulate what happens in reality.
This paper identifies a particular, successful case study where ‘Bench Top’ bottle-testing of produced water samples from a particular crude dehydration plant followed by optimization in the field enabled the plant to meet its required produced water effluent discharge level for total petroleum hydrocarbons (TPH). The ‘Bench Top’ bottle-testing helped to recommend the right type and concentration of reverse emulsion breakers for the particular crude dehydration plant. These products were then applied in the field at the recommended concentrations and optimized until the required produced water effluent discharge level for total petroleum hydrocarbons (TPH) was achieved. The approach, test methods and results are documented.
Leveraging Incumbency to Sustain a Large Gas Business, the Opportunities and Challenges
Authors: Bally Y. K. , Simmons J. , Ingham G. 
Published: June 2012

Abstract
BP Trinidad and Tobago LLC (bpTT) has grown from an oil to a large gas based company over the last 50 years. The company’s discovery of large volumes of gas in the mid 90’s contributed significantly to the rapid development of a thriving Trinidad and Tobago gas based industry, including petrochemical and LNG industries. BP continued to focus on gas based exploration, appraisal and production activities through the decade and has now grown to be in the privileged position of being the largest gas resource holder and producer in Trinidad and Tobago, supplying circa. 2.1bcf/day of daily gas demand. As the industry finding rate, in particular large fields, decreased over the last decade BP has had to look for ways of leveraging its incumbency to increase value for Trinidad and Tobago and BP. Sustaining resource progression and production at current rates is a very challenging and exciting proposition.
The opportunities that present themselves both from a technology and incumbency viewpoint along with the required competency, skills and capability make for a challenge that requires new ways of working. BP has embarked on a multi staged approach; optimizing recovery from the base, applying new technology, commencing an aggressive appraisal program and continuing to explore on existing and new acreage. Clearly the future wells and developments need to be economic and add value to both to Trinidad and Tobago and BP.
Given the time required to progress resources through to production, the pace required to prove resources to continue to support Trinidad and Tobago’s existing gas business provides an exciting and challenging sense of urgency, which demands a different approach to Resource development as compared to what was done in the past. In this paper we will describe the approach, as we define long term sustainability of the gas business for BP and the opportunities and challenges that present themselves.